The following abbreviations and acronyms are used to identify frequently used terms in this report: | | | ALJ | Administrative Law Judge | | AOCL | Accumulated Other Comprehensive Loss | | APB | Accounting Principles Board | | APB 25 | APB Opinion No. 25, "Accounting for Stock Issued to Employees" | | APB 29 | APB Opinion No. 29,“Accounting "Accounting for Nonmonetary Transactions” Transactions" | | ARB | Accounting Research Bulletin | | ARB 43 | ARB No. 43, "Restatement and Revision of Accounting Research Bulletins" | | ARO | Asset Retirement Obligation | | BGS | Basic Generation Service | CAIDI | Customer Average Interruption Duration Index | | CAIR | Clean Air Interstate Rule | | CAL | Confirmatory Action Letter | | CAMR | Clean Air Mercury Rule | | CBP | Competitive Bid Process | CO22 | Carbon Dioxide | | CTC | Competitive Transition Charge | | DOJ | United States Department of Justice | | DRA | Division of the Ratepayer Advocate | | ECAR | East Central Area Reliability Coordination Agreement | | EITF | Emerging Issues Task Force | EITF 03-104-13 | EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain | | Investments”
| EITF 04-13, | EITF Issue No. 04-13,“Accounting “Accounting for Purchases and Sales of Inventory with the SameCounterparty”
| EITF 99-19 | EITF Issue No. 99-19,“Reporting Revenue Gross as a Principal versus Net as an Agent”
Counterparty" | | EPA | Environmental Protection Agency | | EPACT | Energy Policy Act of 2005 |
GLOSSARY OF TERMS Cont'd.
| ERO | Electric Reliability Organization | | FASB | Financial Accounting Standards Board | | FERC | Federal Energy Regulatory Commission | | FIN | FASB Interpretation | | FIN 46R | FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" | | FIN 47 | FASB InterpretationFIN 47,“Accounting "Accounting for Conditional Asset Retirement Obligations - aninterpretation of FASB Statement No. 143”
143" | | FMB | First Mortgage Bonds | FSP | FASB Staff Position | FSP EITF 03-1-1 | FASB Staff Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs 10-20 of EITF Issue | | No. 03-1,The Meaning of Other-Than-Temporary Impairment and Its Application to Certain
| | Investments"
|
GLOSSARY OF TERMS Cont'd
FSP 109-1 | FASB Staff Position No. 109-1,“Application of FASB Statement No. 109, Accounting for IncomeTaxes, to the Tax Deduction on Qualified Production Activities Provided by the American JobsCreation Act of 2004”
| | GAAP | Accounting Principles Generally Accepted in the United States | HVACGCAF | Heating, Ventilation and Air-conditioningGeneration Charge Adjustment Factor | | GHG | Greenhouse Gases | | KWH | Kilowatt-hours | | LOC | Letter of Credit | | MEIUG | Met-Ed Industrial Users Group | | MISO | Midwest Independent Transmission System Operator, Inc. | MSGMoody’s | Market Support GenerationMoody’s Investors Service | | MOU | Memorandum of Understanding | | MTC | Market Transition Charge | | MW | Megawatts | | NAAQS | National Ambient Air Quality Standards | | NERC | North American Electric Reliability Council | | NJBPU | New Jersey Board of Public Utilities | | NOAC | Northwest Ohio Aggregation Coalition | | NOV | Notices of Violation | NOXx | Nitrogen Oxide | | NRC | Nuclear Regulatory Commission | | NUG | Non-Utility Generation | | NUGC | Non-Utility Generation Charge | | OCA | Office of Consumer Advocate | | OCC | Office of the Ohio Consumers' Counsel | | OCI | Other Comprehensive Income | | OPEB | Other Post-Employment Benefits | | OSBA | Office of Small Business Advocate | | OTS | Office of Trial Staff | | PCAOB | Public Company Accounting Oversight Board (United States) | | PICA | Penelec Industrial Customer Association | | PJM | PJM Interconnection L.L.C.L. L. C. | | PLR | Provider of Last Resort | | PPUC | Pennsylvania Public Utility Commission | | PRP | Potentially Responsible Party | | PUCO | Public Utilities Commission of Ohio | | PUHCA | Public Utility Holding Company Act of 1935 | | RCP | Rate Certainty Plan | | RFP | Request for Proposal | | RSP | Rate Stabilization Plan | | RTC | Regulatory Transition Charge | | RTO | Regional Transmission Organization | | S&P | Standard & Poor’s Ratings Service | | SAIFI | System Average Interruption Frequency Index | | SBC | Societal Benefits Charge | | SEC | United StatesU.S. Securities and Exchange Commission | | SFAS | Statement of Financial Accounting Standards | SFAS 71 | SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" | | SFAS 123 | SFAS No. 123, "Accounting for Stock-Based Compensation" | | SFAS 123(R) | SFAS No. 123 (revised 2004)123(R),“Share-Based Payment” | SFAS 131 | SFAS No. 131,“Disclosures about Segments of an Enterprise and Related Information”
"Share-Based Payment" | | SFAS 133 | SFAS No. 133,“Accounting “Accounting for Derivative Instruments and Hedging Activities” Activities” | | SFAS 140 | SFAS No. 140,“Accounting “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities” | | SFAS 143 | Extinguishment of Liabilities”
SFAS No. 143, "Accounting for Asset Retirement Obligations" | | SFAS 144 | SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" | | SFAS 155 | SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140" | SO22 | Sulfur Dioxide | | TBC | Transition Bond Charge |
GLOSSARY OF TERMS Cont'd. | TMI-1 | Three Mile Island Unit 1 | | TMI-2 | Three Mile Island Unit 2 | | VIE | Variable Interest Entity |
PART I. FINANCIAL INFORMATION
FIRSTENERGY CORP. AND SUBSIDIARIES OHIO EDISON COMPANY AND SUBSIDIARIES THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES THE TOLEDO EDISON COMPANY AND SUBSIDIARY PENNSYLVANIA POWER COMPANY AND SUBSIDIARY JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES METROPOLITAN EDISON COMPANY AND SUBSIDIARIES PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1.- ORGANIZATION AND BASIS OF PRESENTATION:PRESENTATION
FirstEnergy’s principal business 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. FirstEnergy's consolidated financial statements also include its other principal subsidiaries: FENOC, FES and its subsidiary FGCO, NGC, FESC FSG, and MYR.FSG.
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 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 these estimates. The reported results of operations are not indicative of results of operations for any future period.
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, 20042005 for FirstEnergy and the Companies. 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 businesses divested in the first quarterand second quarters of 2005 have been classified as discontinued operations on the Consolidated Statements of Income (see Note 6)4). As discussed in Note 15,13, interim period segment reporting in 20042005 was reclassified to conform with the current year business segment organizations and operations.
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. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 9) when it is determined to be the VIE's primary beneficiary. 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, (20-50 percent owned companies, joint ventures and partnerships) are accounted for under the equity method. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheet and the percentage share of the entity’s earnings is reported in the Consolidated Statement of Income. Certain prior year amounts have been reclassified to conform to the current presentation.
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. - ACCOUNTING FOR CERTAIN WHOLESALE ENERGY TRANSACTIONS
FES engages in purchase and sale transactions in the PJM Market to support the supply of end-use customers, including its BGS obligation in New Jersey and PLR requirements in Pennsylvania. In conjunction with FirstEnergy's dedication of its Beaver Valley Plant to PJM on January 1, 2005,FES began accounting for purchase and sale transactions in the PJM Market based on its net hourly position -- recording each hour as either an energy purchase or energy sale. Hourly energy positions are aggregated to recognize gross purchases and sales for the month.
This revised method of accounting, which has no impact on net income, is consistent with the practice of other energy companies that have dedicated generating capacity to PJM and correlates with PJM's scheduling and reporting of hourly energy transactions. In addition, FES applies this methodology to purchase and sale transactions in MISO's energy market, which became active April 1, 2005.
For periods prior to January 1, 2005, FirstEnergy did not have dedicated generating capacity in PJM and as such, FES recognized purchases and sales in the PJM Market by recording each discrete transaction. Under these transactions, FES would often buy a specific quantity of energy at a certain location in PJM and simultaneously sell a specific quantity of energy at a different location. Physical delivery occurred and the risks and rewards of ownership transferred with each transaction.FES has accounted for these transactions on a gross basis in accordance with EITF 99-19.
The FASB's Emerging Issues Task Force is currently considering EITF 04-13, which relates to the accounting for purchases and sales of inventory with the same counterparty. The EITF is expected to address under what circumstances two or more transactions with the same counterparty should be viewed as a single nonmonetary transaction within the scope of APB 29. If the EITF were to determine that transactions such as FES' purchases and sales in the PJM Market should be accounted for as nonmonetary transactions, FES would report the transactions prior to January 1, 2005 on a net basis. This requirement would have no impact on net income, but would reduce both wholesale revenue and purchased power expense by $280 million for the first quarter of 2004.
3. - DEPRECIATION
During the second half of 2004, FirstEnergy engaged an independent third party to assist in reviewing the service lives of its fossil generation units. This study was completed in the first quarter of 2005. As a result of the analysis, FirstEnergy extended the estimated service lives of its fossil generation units for periods ranging from 11 to 33 years during the first quarter of 2005. Extension of the service lives will provide improved matching of depreciation expense with the expected economic lives of those generation units. The change in estimate resulted in a $5.9 million increase (CEI - $2.1 million, OE - $3.3 million, Penn - - $0.1 million, TE - $0.5 million, FGCO - $(0.1) million) in income before discontinued operations and net income ($0.02 per share of common stock) during the first quarter of 2005.
4.2. - 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 0.5 million shares of common stock totaling 0.5 million in the three months ended March 31, 2005 and 3.3 million in the three months ended March 31, 2004, 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 in the three months ended March 31, 2006. The following table reconciles the denominators for basic and diluted earnings per share from Income Before Discontinued Operations:
Reconciliation of Basic and | | Three Months Ended | | Diluted Earnings per Share | | March 31, | | | | | 2005 | | 2004 | | | | | (In thousands) | | | | | | | | | | Income Before Discontinued Operations | | $ | 140,788 | | $ | 172,526 | | | | | | | | | | | | Average Shares of Common Stock Outstanding: | | | | | | | | Denominator for basic earnings per share | | | | | | | | (weighted average shares outstanding) | | | 327,908 | | | 327,057 | | | | | | | | | | | | Assumed exercise of dilutive stock options and awards | | | 1,519 | | | 1,977 | | | | | | | | | | | | Denominator for diluted earnings per share | | | 329,427 | | | 329,034 | | | | | | | | | | | | Income Before Discontinued Operations per common share: | | | | | | | | Basic | | $ | 0.43 | | $ | 0.53 | | Diluted | | $ | 0.42 | | $ | 0.53 | |
| | | Three Months Ended | | Reconciliation of Basic and Diluted | | March 31, | | Earnings per Share | | 2006 | | 2005 | | | | | (In millions) | | | Income Before Discontinued Operations | | $ | 221 | | $ | 141 | | | | | | | | | | | | Average Shares of Common Stock Outstanding: | | | | | | | | | Denominator for basic earnings per share | | | | | | | | | (weighted average shares outstanding) | | | 329 | | | 328 | | | | | | | | | | | | Assumed exercise of dilutive stock options and awards | | | 1 | | | 1 | | | | | | | | | | | | Denominator for diluted earnings per share | | | 330 | | | 329 | | | | | | | | | | | | Income Before Discontinued Operations per common share: | | | | | | | | | Basic | | $ | 0.67 | | $ | 0.43 | | | Diluted | | $ | 0.67 | | $ | 0.42 | |
5.3. - GOODWILL
FirstEnergy's goodwill primarily relates to its regulated services segment. In the three months ended March 31, 2005,2006, FirstEnergy adjusted goodwill related to the divestiture of a non-core operations (FES' natural gas business, the MYR subsidiary, Power Piping Company, and a portion of itsasset (60% interest in FirstCom) as further discussed in Note 6. In addition,MYR), a successful tax claim relating to the former Centerior companies, and an adjustment ofto the former GPU companies' goodwill wascompanies due to the reversalrealization of pre-mergera tax reserves as a result of property tax settlements. FirstEnergy estimatesbenefit that completion of transition cost recovery (see Note 13) will not resulthad been reserved in an impairment of goodwill relating to its regulated business segment.purchase accounting.
A summary of the changes in goodwill for the three months ended March 31, 20052006 is shown below.below:
| | | FirstEnergy | | CEI | | TE | | JCP&L | | Met-Ed | | Penelec | | | | | (In millions) | | | Balance as of January 1, 2005 | | $ | 6,050 | | $ | 1,694 | | $ | 505 | | $ | 1,985 | | $ | 870 | | $ | 888 | | | Non-core asset sales | | | (12 | ) | | -- | | | -- | | | -- | | | -- | | | -- | | | Adjustments related to GPU acquisition | | | (4 | ) | | -- | | | -- | | | (1 | ) | | (2 | ) | | (1 | ) | | Balance as of March 31, 2005 | | $ | 6,034 | | $ | 1,694 | | $ | 505 | | $ | 1,984 | | $ | 868 | | $ | 887 | |
| | | FirstEnergy | | CEI | | TE | | JCP&L | | Met-Ed | | Penelec | | | | | (In millions) | | | Balance as of January 1, 2006 | | $ | 6,010 | | $ | 1,689 | | $ | 501 | | $ | 1,986 | | $ | 864 | | $ | 882 | | | Non-core assets sale | | | (53 | ) | | | | | | | | | | | | | | | | | Adjustments related to Centerior acquisition | | | (1 | ) | | (1 | ) | | | | | | | | | | | | | | Adjustments related to GPU acquisition | | | (16 | ) | | | | | | | | (8 | ) | | (4 | ) | | (4 | ) | | Balance as of March 31, 2006 | | $ | 5,940 | | $ | 1,688 | | $ | 501 | | $ | 1,978 | | $ | 860 | | $ | 878 | |
6.4. - DIVESTITURES AND DISCONTINUED OPERATIONS
In December 2004, FES'March 2006, FirstEnergy sold 60% of its interest in MYR for an after-tax gain of $0.2 million. As a result, FirstEnergy deconsolidated MYR and began accounting for its remaining 40% interest under the equity method. In March 2005, FES sold its retail natural gas business qualifiedfor an after-tax gain of $5 million and FirstEnergy sold 51% of its interest in FirstCom for an after-tax gain of $4 million. FirstEnergy accounts for its remaining 31.85% interest in FirstCom under the equity method.
FirstEnergy sold two FSG subsidiaries (Elliott-Lewis and Spectrum) and an MYR subsidiary (Power Piping Company) in the first quarter of 2005, resulting in aggregate after-tax gains of $12 million. The remaining FSG subsidiaries continue to be actively marketed and qualify as assets held for sale in accordance with SFAS 144. OnManagement anticipates that the transfer of FSG assets, with a net carrying value of $49 million as of March 31, 2005, FES2006, will qualify for recognition as completed the sale for an after-tax gainsales within one year. As of $5 million.
In March 2005, FirstEnergy sold 51% of its interest in FirstCom, resulting in an after-tax gain of $4 million. FirstEnergy will account for its remaining 31.85% interest in FirstCom on31, 2006, the equity basis.
In the first quarter of 2005, FirstEnergy sold its FSG subsidiaries Elliott-Lewis and Spectrum, and MYR subsidiary, Power Piping Company, resulting in an after-tax gain of $12 million. FSG's remaining subsidiaries qualifiedclassified as held for sale in accordance with SFAS 144 and are expected to be recognized as completed sales bydid not meet the fourth quartercriteria for discontinued operations. The carrying amounts of 2005. TheFSG's assets and liabilities of these remaining FSG subsidiariesheld for sale are not material to FirstEnergy’s Consolidated Balance Sheet as of March 31, 2005 and have therefore not been separately classified as assets held for sale.sale on FirstEnergy's Consolidated Balance Sheets. See Note 13 for FSG's segment financial information.
Net income (including the gain on sales gains discussed above) for Elliott-Lewis, Power Piping, and FES' natural gas business and Cranston (sold in the second quarter of 2005) of $19 million for the first quarter of 2005 and $1 million for the first quarter of 2004 areis reported as discontinued operations on FirstEnergy's Consolidated Statements of Income. Pre-tax operating results for these entities were $4 million for the first quarter of 2005 and $3 million for the first quarter of 2004.2005. Revenues associated with discontinued operations for the first quarter of 2005 and 2004 were $191 million and $186 million, respectively. It is not certain that$195 million. The following table summarizes the remaining FSG businesses will meet the criteria forsources of income from discontinued operations; therefore, the net loss ($2 millionoperation for the first quarter of 2005 and $1 million for the first quarter of 2004) from these subsidiaries has not been included in discontinued operations. See Note 15 for FSG's segment financial information.three months ended March 31, 2005:
| | | Three Months Ended | | | | | March 31, | | | | | 2005 | | 2004 | | | | | (In millions) | | | Discontinued Operations (Net of tax) | | | | | | | Gain on sale: | | | | | | Natural gas business | | $ | 5 | | $ | -- | | Elliot-Lewis, Spectrum and Power Piping | | | 12 | | | -- | | | Reclassification of operating income | | | 2 | | | 1 | | | Total | | $ | 19 | | $ | 1 | |
| | | (In millions) | | | Discontinued Operations (Net of tax) | | | | | Gain on sale: | | | | | Natural gas business | | $ | 5 | | | FSG subsidiaries and Power Piping | | | 12 | | | Reclassification of operating income | | | 2 | | | Total | | $ | 19 | |
7.5. - DERIVATIVE INSTRUMENTS
FirstEnergy has entered intois exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. 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. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.
FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value hedges of fixed-rate, long-term debt issues to protect againstunless they meet the risk ofnormal purchase and normal sales criteria. Derivatives that meet that criterion are accounted for on the accrual basis. The changes in the fair value of fixed-rate debtderivative instruments due to lower interest rates.Swap maturities, call options, fixed interest rates received,that do not meet the normal purchase and interest payment dates match thosesales criteria are recorded in current earnings, in AOCL, or as part of the underlying debt obligations. As of March 31, 2005, FirstEnergy had fixed-for-floating interest rate swap agreements with anaggregate notional amount of $1.75 billion. During the first quarter of 2005, FirstEnergy executed new interest rate swaps with a total notional amount of $100 million. 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 6.51%. The interest rate swaps have effectively converted that rate to a current, weighted average variable interest rate of 4.91%.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 toitem, depending on whether or not it is designated as part of a recognized asset, liability, or unrecognized firm commitment are recorded in earnings. Sincehedge transaction, the fair value hedges are effective,nature of the amounts recorded will be offset in earnings. hedge transaction and hedge effectiveness.
FirstEnergy engages in hedging ofhedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases and anticipated interest payments associated with future debt issues. The effective portion of such hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings.
The net deferred losslosses of $87$53 million included in AOCL as of March 31, 2005,2006, for derivative hedging activity, as compared to the December 31, 20042005 balance of $92$78 million inof net deferred losses, resulted from a $5$19 million reductiondecrease related to current hedging activity a $4 million increase due to the sale of gas business contracts and a $4$6 million decrease due to net hedge losses included in earnings during the three months ended March 31, 2005.2006. Approximately $10$11 million (after tax) of the net deferred losslosses on derivative instruments in AOCL as of March 31, 20052006 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments will fluctuate from period to period based on various market factors. FirstEnergy has entered into swaps that have been designated as 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. During the first quarter of 2006, FirstEnergy unwound swaps with a total notional amount of $350 million for which it paid $1 million in cash. The losses will be recognized in earnings over the remaining maturity of each respective hedged security as increased interest expense. As of March 31, 2006, the aggregate notional value of interest rate swap agreements outstanding was $750 million.
During 2005 and the first quarter of 2006, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated issuances of fixed-rate, long-term debt securities for one or more of its consolidated entities during 2006 - 2008 as outstanding debt matures. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first quarter of 2006, FirstEnergy revised its financing plan related to forward swaps with an aggregate notional amount of $500 million, impacting the term and timing of the respective issuances. As required by SFAS 133, FirstEnergy de-designated the forward swaps and assessed the amount of ineffectiveness. FirstEnergy terminated the forward swaps and received cash of $16 million, of which approximately $5 million ($3 million net of tax) was deemed ineffective and recognized in earnings in the first quarter of 2006. The remaining gain deemed effective in the amount of approximately $11 million ($7 million net of tax) was recorded in other comprehensive income and will subsequently be recognized in earnings over the terms of the respective forward swaps. As of March 31, 2006, FirstEnergy had forward swaps with an aggregate notional amount of $1 billion and a fair value of $25 million. 8.6. - STOCK BASED COMPENSATION
FirstEnergy applieshas the following stock-based compensation programs: Long-term Incentive Program (LTIP); Executive Deferred Compensation Plan (EDCP); Employee Stock Ownership Plan (ESOP) and Deferred Compensation Plan for Outside Directors (DCPD), which were previously accounted for under the recognition and measurement principles of APB 25 and related interpretations in accounting for itsinterpretations. The LTIP includes four stock-based compensation plans. No materialprograms - restricted stock, restricted stock units, stock options, and performance shares.
Effective January 1, 2006, FirstEnergy adopted SFAS 123(R), which requires the expensing of stock-based employeecompensation. Under SFAS 123(R), all share-based compensation cost is measured at the grant date, based on the fair value of the award and is recognized as an expense over the employee’s requisite service period. FirstEnergy adopted the modified prospective method, under which compensation expense isrecognized in the first quarter of 2006 includes the expense for all share-based payments granted prior to but not yet vested as of January 1, 2006. Results for prior periods have not been restated.
Under APB 25, no compensation expense was reflected in net income for stock options 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 December 2004, the FASB issued a revision to SFAS 123 which requires expensing the fair value of The pro-forma effects on net income for stock options (see Note 14). In April 2005,were instead disclosed in a footnote to the SEC delayed the effective date offinancial statements. Under APB 25 and SFAS 123(R) expense was recorded in the income statement for restricted stock, restricted stock units, performance shares and the EDCP and DCPD programs. No stock options have been issued subsequent to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule results in a six-month deferral for FirstEnergy and other companies with a fiscal year beginning January 1. The table below summarizes the effects on FirstEnergy’sthird quarter of 2004. Consequently, the impact of adopting SFAS 123(R) was not material to FirstEnergy's net income and earnings per share had FirstEnergy appliedin the fair value recognition provisionsfirst quarter 2006. In the year of adoption all disclosures prescribed by SFAS 123(R) are required to be included in both the quarterly Form 10-Q filings as well as the annual Form 10-K filing. However, due to the immaterial impact of the adoption of SFAS 123 to stock-based employee compensation in the current reporting periods.123(R) on FirstEnergy's financial results, only condensed disclosure has been provided. For annual disclosures see FirstEnergy's 2005 Form 10-K.
The following table illustrates the effect on net income and earnings per share for the first quarter of 2005, as if FirstEnergy had adopted SFAS 123(R) as of January 1, 2005 (in millions):
| | | Three Months Ended | | | March 31, | | | | | March 31, | | | 2005 | | | Net Income, as reported | | | $ | 160 | | | | | 2005 | | 2004 | | | | | | | | | (In thousands) | | | | | | | | | | | | | | | Net income, as reported | | $ | 159,726 | | $ | 173,999 | | | | | | | | | | | | | | Add back compensation expense | | | | | | | | | | | | reported in net income, net of tax | | | | | | | | | (based on APB 25)* | | | 7,969 | | | 6,694 | | | reported in net income, net of tax (based on | | | | 8 | | APB 25)* | | | | | | | | | | | | | | | | | | | | Deduct compensation expense based | | | | | | | | | | | | upon estimated fair value, net of tax | | | (11,026 | ) | | (11,098 | ) | | upon estimated fair value, net of tax* | | | | (11 | ) | | | | | | | | | | | | | | | Pro forma net income | | $ | 156,669 | | $ | 169,595 | | | $ | 157 | | | | | | | | | | | | | Earnings Per Share of Common Stock - | | | | | | | | | | | | Basic | | | | | | | | | | | | As Reported | | $ | 0.49 | | $ | 0.53 | | | $ | 0.49 | | Pro Forma | | $ | 0.48 | | $ | 0.52 | | | $ | 0.48 | | Diluted | | | | | | | | | | | | As Reported | | $ | 0.48 | | $ | 0.53 | | | $ | 0.48 | | Pro Forma | | $ | 0.48 | | $ | 0.52 | | | $ | 0.48 | |
* Includes restricted stock, restricted stock units, stock options, performance shares, Employee Stock Ownership Plan, Executive Deferred Compensation Planshares, ESOP, EDCP and Deferred Compensation Plan for Outside Directors.DCPD.
FirstEnergy has reduced its use of stock options and increased its use of performance-based, restricted stock units. Therefore, the pro forma effects of applying SFAS 123 may not be representative of its future effect. FirstEnergy has not and does not expect to accelerate out-of-the-money options in anticipation of implementing SFAS 123(R) on January 1, 2006 (see Note 14 - "New Accounting Standards and Interpretations").
9.7. - ASSET RETIREMENT OBLIGATIONS
FirstEnergy has identifiedrecognized applicable legal obligations under SFAS 143 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. In addition, FirstEnergy has recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47, which was implemented on December 31, 2005. Had FIN 47 been applied in the first quarter of 2005, the impact on earnings would have been immaterial.
The ARO liability of $1.095$1.1 billion as of March 31, 2005 included $1.071 billion for2006 primarily related to the 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 to measure the fair value of the nuclear decommissioning ARO. The Companies maintain FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of March 31, 2005,2006, the fair value of the decommissioning trust assets was $1.604$1.8 billion.
The following tables provide the beginning and ending aggregate carrying amount of the ARO and theanalyze changes to the ARO balance during the three months ended March 31,first quarters of 2006 and 2005, and 2004, respectively.
ARO Reconciliation | | | FirstEnergy | | OE | | CEI | | TE | | Penn | | JCP&L | | Met-Ed | | Penelec | | | | | FirstEnergy | | OE | | CEI | | TE | | Penn | | JCP&L | | Met-Ed | | Penelec | | | (In millions) | | ARO Reconciliation | | (In millions) | | | | Balance, January 1, 2006 | | | $ | 1,126 | | $ | 83 | | $ | 8 | | $ | 25 | | $ | - | | $ | 80 | | $ | 142 | | $ | 72 | | | Liabilities incurred | | | | - | | - | | - | | - | | - | | - | | - | | - | | | Liabilities settled | | | | - | | - | | - | | - | | - | | - | | - | | - | | | Accretion | | | | 18 | | 1 | | - | | - | | - | | 1 | | 2 | | 1 | | | Revisions in estimated cash flows | | | | 4 | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Balance, March 31, 2006 | | | $ | 1,148 | | $ | 84 | | $ | 8 | | $ | 25 | | $ | - | | $ | 81 | | $ | 144 | | $ | 73 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance, January 1, 2005 | | $ | 1,078 | | $ | 201 | | $ | 272 | | $ | 194 | | $ | 138 | | $ | 73 | | $ | 133 | | $ | 66 | | | $ | 1,078 | | $ | 201 | | $ | 272 | | $ | 194 | | $ | 138 | | $ | 73 | | $ | 133 | | $ | 66 | | | Liabilities incurred | | | -- | | -- | | -- | | -- | | -- | | -- | | -- | | -- | | | | - | | - | | - | | - | | - | | - | | - | | - | | | Liabilities settled | | | -- | | -- | | -- | | -- | | -- | | -- | | -- | | -- | | | | - | | - | | - | | - | | - | | - | | - | | - | | | Accretion | | | 17 | | 3 | | 4 | | 3 | | 2 | | 2 | | 2 | | 1 | | | | 17 | | 3 | | 4 | | 3 | | 2 | | 2 | | 2 | | 1 | | | Revisions in estimated cash flows | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Balance, March 31, 2005 | | $ | 1,095 | | $ | 204 | | $ | 276 | | $ | 197 | | $ | 140 | | $ | 75 | | $ | 135 | | $ | 67 | | | $ | 1,095 | | $ | 204 | | $ | 276 | | $ | 197 | | $ | 140 | | $ | 75 | | $ | 135 | | $ | 67 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance, January 1, 2004 | | $ | 1,179 | | $ | 188 | | $ | 255 | | $ | 182 | | $ | 130 | | $ | 110 | | $ | 210 | | $ | 105 | | | | Liabilities incurred | | | -- | | -- | | -- | | -- | | -- | | -- | | -- | | -- | | | | Liabilities settled | | | -- | | -- | | -- | | -- | | -- | | -- | | -- | | -- | | | | Accretion | | | 19 | | 3 | | 4 | | 3 | | 2 | | 1 | | 3 | | 2 | | | | Revisions in estimated cash flows | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | | Balance, March 31, 2004 | | $ | 1,198 | | $ | 191 | | $ | 259 | | $ | 185 | | $ | 132 | | $ | 111 | | $ | 213 | | $ | 107 | | |
10.8. - PENSION AND OTHER POSTRETIREMENT BENEFITS:
FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy also provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing other postretirement benefits to employees, their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits.
The components of FirstEnergy's net periodic pension cost and other postretirement benefit cost (including amounts capitalized) as offor the three months ended March 31, 20052006 and 2004,2005, consisted of the following:
| | | Pension Benefits | | Other Postretirement Benefits | | | | | Other Postretirement | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | Pension Benefits | | Benefits | | | | | | | (In millions) | | | | | 2006 | | 2005 | | 2006 | | 2005 | | | | | | | | | | | | | | | | (In millions) | | | | | Service cost | | $ | 19 | | $ | 19 | | $ | 10 | | $ | 11 | | | $ | 21 | | $ | 19 | | $ | 9 | | $ | 10 | | | Interest cost | | | 64 | | | 63 | | | 28 | | | 33 | | | | 66 | | | 64 | | | 26 | | | 28 | | | Expected return on plan assets | | | (86 | ) | | (71 | ) | | (11 | ) | | (13 | ) | | | (99 | ) | | (86 | ) | | (12 | ) | | (11 | ) | | Amortization of prior service cost | | | 2 | | | 2 | | | (11 | ) | | (12 | ) | | | 2 | | | 2 | | | (19 | ) | | (11 | ) | | Recognized net actuarial loss | | | 9 | | | 10 | | | 10 | | | 11 | | | | 15 | | | 9 | | | 14 | | | 10 | | | Net periodic cost | | $ | 8 | | $ | 23 | | $ | 26 | | $ | 30 | | | $ | 5 | | $ | 8 | | $ | 18 | | $ | 26 | |
Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net periodic pension costs (credits) and net periodic postretirement benefit costs (including amounts capitalized) recognized by each of the Companies infor the three months ended March 31, 20052006 and 20042005 were as follows: | | | Pension Benefit Cost (Credit) | | Other Postretirement Benefit Cost | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | | | (In millions) | | | | | | | | | | | | | | | | OE | | $ | 0.2 | | $ | 1.7 | | $ | 5.8 | | $ | 7.1 | | | Penn | | | (0.2 | ) | | 0.1 | | | 1.2 | | | 1.5 | | | CEI | | | 0.3 | | | 1.6 | | | 3.8 | | | 5.6 | | | TE | | | 0.3 | | | 0.8 | | | 2.2 | | | 2.0 | | | JCP&L | | | (0.2 | ) | | 1.9 | | | 2.7 | | | 1.6 | | | Met-Ed | | | (1.1 | ) | | 0.1 | | | 0.4 | | | 1.3 | | | Penelec | | | (1.3 | ) | | 0.1 | | | 1.9 | | | 1.4 | |
| | | Pension Benefit Cost (Credit) | | Other Postretirement Benefit Cost | | | | | 2006 | | 2005 | | 2006 | | 2005 | | | | | | | (In millions) | | | | | OE | | $ | (1.1 | ) | $ | 0.2 | | $ | 3.4 | | $ | 5.8 | | | Penn | | | (0.4 | ) | | (0.2 | ) | | 0.8 | | | 1.2 | | | CEI | | | 1.0 | | | 0.3 | | | 2.8 | | | 3.8 | | | TE | | | 0.2 | | | 0.3 | | | 2.0 | | | 2.2 | | | JCP&L | | | (1.4 | ) | | (0.2 | ) | | 0.6 | | | 2.7 | | | Met-Ed | | | (1.7 | ) | | (1.1 | ) | | 0.7 | | | 0.4 | | | Penelec | | | (1.3 | ) | | (1.3 | ) | | 1.8 | | | 1.9 | | Other FirstEnergy subsidiaries | | | 9.9 | | | 9.5 | | | 6.1 | | | 8.1 | | | | | $ | 5.2 | | $ | 7.5 | | $ | 18.2 | | $ | 26.1 | |
11.9. - VARIABLE INTEREST ENTITIES
FIN 46R addresses the consolidation of VIEs, including special-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the entity's residual economic risks and rewards. FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary as defined by FIN 46R.
Leases
Included in FirstEnergy’s consolidated financial statements areinclude PNBV and Shippingport, two VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with the 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-percent3% equity interest by a nonaffiliatedan unaffiliated third party and a three-percent3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. 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.
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 $688$666 million, $99$96 million and $566$535 million, respectively, that would not be payable if the casualty value payments are made.
Power Purchase Agreements In accordance with FIN 46R, FirstEnergy 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 Penelec, maintains approximately 30 long-term power purchase agreements with NUG entities. The agreements were structuredentered into 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 nineeight of these entities, neither JCP&L, Met-Ed nor 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 nineeight 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 periodically requests from these nineeight entities the information necessary 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 proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The
Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss fromrelates primarily to the above-market costs it incurs for power. As of March 31, 2006, the net projected above-market loss liability recognized for these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data.eight NUG agreements was $102 million. Purchased power costs from these entities during the first quarters of 20052006 and 20042005 are shown in the table below:
| | | Three Months Ended | | | Three Months Ended | | | | | March 31, | | | March 31, | | | | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | (In millions) | | | JCP&L | | $ | 27 | | $ | 28 | | | $ | 15 | | $ | 21 | | | Met-Ed | | | 16 | | | 16 | | | | 16 | | | 16 | | | Penelec | | | 7 | | | 7 | | | | 8 | | | 7 | | | | | $ | 50 | | $ | 51 | | | $ | 39 | | $ | 44 | |
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.
12.10. - COMMITMENTS, GUARANTEES AND CONTINGENCIES:
(A) GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. SuchThese agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions.LOCs. As of March 31, 2005,2006, outstanding guarantees and other assurances aggregatedtotaled approximately $2.4$3.3 billion and included-- contract guarantees ($1.01.8 billion), surety bonds ($0.30.2 billion) and LOCLOCs ($1.11.3 billion).
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity 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 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$1.8 billion discussed above) as of March 31, 2005 will2006 would increase amounts otherwise to be paidpayable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related contracts.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 “material adverse event”event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect asAs of March 31, 2005:2006, FirstEnergy's maximum exposure under these collateral provisions was $456 million.
| | | | | Collateral Paid | | Remaining | | Collateral Provisions | | Exposure | | Cash | | LOC | | Exposure(1) | | | | | (In millions) | | | Credit rating downgrade | | $ | 364 | | $ | 153 | | $ | 18 | | $ | 193 | | | Adverse Event | | | 42 | | | -- | | | 8 | | | 34 | | | Total | | $ | 406 | | $ | 153 | | $ | 26 | | $ | 227 | |
(1) | As of May 2, 2005, FirstEnergy’s total exposure decreased to $357 million and the remaining exposure decreased
to $183 million - net of $148 million of cash collateral and $26 million of LOC collateral provided by counterparties.
|
Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $267$136 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. The Companies, with the exception of TE and JCP&L, each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company.
| | | | | Borrowing | | Subsidiary Company | | Parent Company | | Capacity | | | | | | | (In millions) | | | OES Capital, Incorporated | | | OE | | $ | 170 | | | Centerior Funding Corp. | | | CEI | | | 200 | | | Penn Power Funding LLC | | | Penn | | | 25 | | | Met-Ed Funding LLC | | | Met-Ed | | | 80 | | | Penelec Funding LLC | | | Penelec | | | 75 | | | | | | | | $ | 550 | |
FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC (currently at $47 million)($36 million as of March 31, 2006), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.
(B) 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 compliance with existing regulations but is unable to predict future changechanges in regulatory policies and what, if any, the effects of such changechanges would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $430 million$1.8 billion for 20052006 through 2007.2010.
The Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably determineestimate 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.
On December 1, 2005, FirstEnergy issued a comprehensive report to shareholders regarding air emissions regulations and an assessment of its future risks and mitigation efforts.
Clean Air Act Compliance
The Companies are FirstEnergy 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 $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The CompaniesFirstEnergy cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The Companies believe they are FirstEnergy 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. NOxX 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 NOxX reductions from the Companies'FirstEnergy's facilities. The EPA's NOxX Transport Rule imposes uniform reductions of NOxX emissions (an approximate 85 percent85% reduction in utility plant NOxX 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 NOxX emissions are contributing significantly to ozone levels in the eastern United States. The Companies believe theirFirstEnergy believes its facilities are also complying with the NOxX budgets established under State Implementation Plans 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 March 10, 2005, the EPA finalized the "Clean Air Interstate Rule"CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainmentnon-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR will requireprovides each affected state until 2006 to develop implementing regulations to achieve additional reductions of NOxX and SO2 emissions in two phases (Phase I in 2009 for NOx,NOx, 2010 for SO2 and Phase II in 2015 for both NOxNOX and SO2). The Companies’FirstEnergy's Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO2 and NOxNOx emissions, whereas ourits New Jersey fossil-fired generation facilities will be subject to only a cap on NOxX emissions only.emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOx emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOxX cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which the Companies operateFirstEnergy operates 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 March 14, 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants.plants in two phases. Initially, mercury emissions will declinebe capped nationally at 38 tons by 2010 as(as a "co-benefit" from implementation of SO2 and NOxXemission caps under the EPA's CAIR program.program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. TheHowever, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial.substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.
The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FirstEnergy would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced. Since this approach is based on output, new and non-emitting generating facilities, including renewables and nuclear, would be entitled to their proportionate share of the allowances. Consequently, FirstEnergy would be disadvantaged if these model rules were implemented because its substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.
W. H. Sammis Plant
In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities coveringalleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which iswas owned at that time by OE and Penn. In addition, the U.S. Department of Justice (DOJ)DOJ filed eight civil complaints against various investor-owned utilities, which includedincluding 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. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement which is inwas approved by the form of a Consent Decree subject to a thirty-day public comment period that endedCourt on April 29,July 11, 2005, and final approval by the District Court Judge, requires OEreductions of NOX and Penn to reduceSO2 emissions fromat the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices requiring capitaland provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the settlement agreement. Capital expenditures necessary to meet those requirements are currently estimated to be $1.1$1.5 billion (primarily(the primary portion of which is expected to be spent in the 2008 to 2011 time period). On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million towardstoward environmentally beneficial projects, which include wind energy purchasepurchased power agreements over a 20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 includeincluded the penalties payablepaid by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also accruedrecognized liabilities in the first quarter of 2005 of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects during the first quarter of 2005.projects. 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 gasesGHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote ofrequired for ratification by the United States Senate required for ratification.Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gasGHG intensity - the ratio of emissions to economic output - by 18 percent18% through 2012. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.
The Companies FirstEnergy 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, theThe CO2 emissions per kilowatt-hour of electricity generated by the CompaniesFirstEnergy is lower than many regional competitors due to the Companies'its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
FirstEnergy plans to issue a report that will disclose the Companies’ environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by December 1, 2005.
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'FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to the Companies'FirstEnergy's 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 Section 316(b) of the Clean Water Act 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 areFirstEnergy is conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by theirits 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 require material capital expenditures.
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 March 31, 2005,2006, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliatedunaffiliated 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 accruedTotal liabilities aggregatingof approximately $65$63 million (JCP&L - $46.8$47.3 million, CEI - $2.3$1.7 million, TE - $0.2 million, Met-Ed - $48,000$0.05 million and other - $15.2$13.7 million) as ofhave been accrued through March 31, 2005.2006.
(C) OTHER LEGAL PROCEEDINGS
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 of New Jersey’s 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 product 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 CourtDivision 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 JCP&L 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.Division. In December, 2005, JCP&L has filed aargued its motion for summary judgment.judgment before the New Jersey Superior Court on its renewed motion to decertify the class and on remaining plaintiffs' negligence and breach of contract claims. These motions remain pending. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of March 31, 2005.2006.
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. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically, the final report concludes,concluded, 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 real-time 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 contained 46“recommendations “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in process,new or material upgrades to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother applicable government agencies and reliability coordinators may, however, 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 asFinally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of March 31, 2005 forcontrol room operators before determining the next steps, if any, expenditures in excess of those actually incurred through that date.the proceeding.
Three substantially similar actions FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in various Ohio State courts by plaintiffs seekingbut were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent customers whoothers as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these four cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc. as well) for claims paid to insureds for damages allegedly suffered damagesarising as a result of the loss of power on August 14, 2003 power outages. All three2003. The listed insureds in these cases, werein many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. On March 7, 2006, the PUCO issued a ruling applicable to all pending cases. Among its various rulings, the PUCO consolidated all of the pending outage cases for hearing; limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence; and gave the plaintiffs additional time to amend their complaints to otherwise comply with the PUCO’s underlying order. The plaintiffs in one case have since filed an amended complaint. The named FirstEnergy companies have answered and also have filed a motion to dismiss the action, which is pending. Also, most complainants, along with the FirstEnergy companies, filed applications for lackrehearing with the PUCO over various rulings contained in the March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow the insurance company claimants, as insurers, to prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities which provide their service. The PUCO denied all other motions for rehearing. No estimate of jurisdiction. One case was refiled on January 12, 2004 at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. In the remaining case, the Courtpotential liability is available for any of Appeals on March 31, 2005 affirmed the trial court’s decision dismissing the case. It is not yet known whether further appeal will be sought.these cases. In addition to the one case that was refiled at the PUCO,these six cases, 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. Following the PUCO's March 7, 2006 order, that action was voluntarily dismissed by the claimants.
In addition to the above proceedings, FirstEnergy was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter has been filed. FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy are based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. No FirstEnergy entity serves any customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. It is uncertain whether the plaintiff will appeal. No estimate of potential liability has been undertaken in either of these matters.
One complaint was filed on August 25, 2004 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 timetable for a decision on the motion to dismiss has been established by the Court. 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 initiated against the Companies. In particular,Although unable to predict the impact of these proceedings, 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.operations and cash flows.
Nuclear Plant Matters
On January 20, 2006, FENOC receivedannounced that it has entered into a subpoena in late 2003 from a grand jury sitting indeferred prosecution agreement with the United States District CourtU.S. Attorney’s Office for the Northern District of Ohio Eastern Division requestingand the production of certain documents and records relating to the inspection and maintenanceEnvironmental Crimes Section of the Environment and Natural Resources Division of the DOJ related to FENOC’s communications with the NRC during the fall of 2001 in connection with the reactor vessel head issue at the Davis-Besse Nuclear Power Station. OnUnder the agreement, which expires on December 10, 2004, FirstEnergy received a letter from31, 2006, the United States Attorney's Office stating thatacknowledged FENOC’s extensive corrective actions at Davis-Besse, FENOC’s cooperation during investigations by the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related criminal and administrative investigations and proceedings, FENOC’s acknowledgement of responsibility for the behavior of its employees, and its agreement to pay a monetary penalty. The DOJ will refrain from seeking an indictment or otherwise initiating criminal prosecution of FENOC is a target of the federal grand jury investigation into alleged false statements madefor all conduct related to the NRCstatement of facts attached to the deferred prosecution agreement, as long as FENOC remains in compliance with the agreement, which FENOC fully intends to do. FENOC paid a monetary penalty of $28 million (which is not deductible for income tax purposes) which reduced First Energy's earnings by $0.09 per common share in the Fallfourth quarter of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse.2005. On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head describedissue discussed above. Under the NRC’s letter, FENOC has ninety daysFirstEnergy accrued $2 million for a potential fine prior to respond to this NOV. FirstEnergy2005 and accrued the remaining liability for the proposed fine of $3.45 million during the first quarter of 2005. If it were ultimately determined On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy orpaid the penalty in the third quarter of 2005. On January 23, 2006, FENOC supplemented its subsidiaries has legal liability basedresponse to the NRC's NOV on the Davis-Besse head degradation it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.to reflect the deferred prosecution agreement that FENOC had reached with the DOJ.
On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the pastpreceding two years.years and the licensee's failure to take prompt and corrective action. FENOC operates the Perry Nuclear Power Plant, which is owned and/or leased by OE, CEI, TE and Penn.OnPlant.
On April 4, 2005, the NRC held a public forummeeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Nuclear Power Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives althougheven though it remained under the heightened NRC oversight since August 2004.oversight. During the public forummeeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. By an inspection report dated January 18, 2006, the NRC closed one of the White Findings (related to emergency preparedness) which led to the multiple degraded cornerstones.
On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's 2005 annual assessment letter dated March 2, 2006 and associated meetings to discuss the performance of Perry on March 14, 2006, the NRC again stated that the Perry Plant continued to operate in a manner that "preserved public health and safety." However, the NRC also stated that increased levels of regulatory oversight would continue until sustained improvement in the performance of the facility was realized. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these mattersAlthough FirstEnergy is unable to predict the impact of the ultimate disposition of this matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.condition, results of operations and cash flows.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The most significantother potentially material items 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, have 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. On December 30, 2004, FirstEnergy received a second subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse-related disclosures, which has been provided. FirstEnergy has cooperated fully with the informal inquiry and will continuecontinues to do so with the formal investigation.
On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.
JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, the federal court granted a Union motion to dismiss JCP&L's appeal of the award as premature. JCP&L will file its appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.
The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly-formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO of a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will decide this case.
If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matter,matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, and results of operations.operations and cash flows.
13.11. - REGULATORY MATTERS:
Reliability InitiativesRELIABILITY INITIATIVES
In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training and emergency response preparedness recommended for completion in 2004. On July 14, 2004, NERC independently verified that FirstEnergy had implemented the various initiatives to be completed by June 30 or summer 2004, with minor exceptions noted by FirstEnergy, which exceptions are now essentially complete. FirstEnergy is proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades to existing equipment. FirstEnergy notes, however, thatThe FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future as the result of adoption of mandatory reliability standards pursuant to the EPACT that could require additional, material expenditures. Finally, the PUCO is continuing to review the FirstEnergy filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.
As a result of outages experienced in JCP&L's&L’s service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L's&L’s service reliability. On March 29,In 2004, the NJBPU adopted a Memorandum of Understanding (MOU)MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L's&L’s ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a stipulationStipulation that incorporates the final report of a Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulationStipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L's&L’s Planning and Operations and Maintenance programs and practices (Focused Audit). A final order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer AdvocateDRA to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.
In May 2004, the PPUC issued an order approving revised reliability benchmarks and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, due to their implementation of automated outage management systems following restructuring. Evidentiary hearings have been scheduled for September 2005. FirstEnergy is unable to predictOn December 30, 2005, the outcome of this proceeding. In November 2004,ALJ recommended that the PPUC adopt the Joint Petition for Settlement among the parties involved in the three Companies’ request to amend the distribution reliability benchmarks, thereby eliminating the need for full litigation. The ALJ’s recommendation, adopting the revised benchmarks and standards, was approved a settlement agreement filed by Met-Ed, Penelec and Penn that addressed issues related to athe PPUC investigation into Met-Ed's, Penelec's and Penn's service reliability performance. As part of the settlement, Met-Ed, Penelec and Penn agreed to enhance service reliability, ongoing periodic 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 distributionFebruary 9, 2006.
The EPACT provides for the years 2005 through 2007.creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC review. On February 3, 2006, the FERC adopted a rule establishing certification requirements for the ERO, as well as regional entities envisioned to assume monitoring responsibility for the new reliability standards. The settlement also outlinesFERC issued an expedited remediation process to address any alleged non-compliance with terms oforder on rehearing on March 30, 2006, providing certain clarifications and essentially affirming the settlement and an expedited PPUC hearing process if remediation is unsuccessful.rule.
The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC’s certification requirements for the ERO. The NERC made a filing with the FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC approval of delegation agreements with regional entities. The new FERC rule referred to above, further provides for reorganizing regional reliability organizations (regional entities) that would replace the current regional councils and for rearranging the relationship with the ERO. The “regional entity” may be delegated authority by the ERO, subject to FERC approval, for enforcing reliability standards adopted by the ERO and approved by the FERC. NERC also made a parallel filing with the FERC April 4, 2006 seeking approval of mandatory reliability standards. These reliability standards are based with some modifications, on the current NERC Version O reliability standards with some additional standards. On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security standards and thirteen additional reliability standards. These standards will become effective on June 1, 2006 and will be filed with the FERC and relevant Canadian authorities for approval. The two filings are subject to review and acceptance by the FERC.
The ERO filing was noticed on April 7, 2006 and comments and interventions were filed on May 4, 2006. There is no fixed time for the FERC to act on this filing. The reliability standards filing was noticed by FERC on April 18, 2006. In that notice FERC announced its intent to treat the proposed reliability standards as a Notice of Proposed Rulemaking (NOPR), and issue a NOPR in July 2006. Prior to that time, the FERC staff will release a preliminary assessment of the proposed reliability standards. FERC also intends to hold a technical conference on the proposed reliability standards. A comment period will be set after the Staff assessment is released and the technical conference is held. NERC has requested an effective date of January 1, 2007 for the reliability standards.
The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils have completed the consolidation of these regions into a single new regional reliability organization known as ReliabilityFirst Corporation. ReliabilityFirst began operations as a regional reliability council under NERC on January 1, 2006 and intends to file and obtain certification consistent with the final rule as a “regional entity” under the ERO during 2006. All of FirstEnergy’s facilities are located within the ReliabilityFirst region.
FirstEnergy believes it is in compliance with all current NERC reliability standards. However, it is expected that the FERC will adopt stricter reliability standards than those contained in the current NERC standards. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates.
OhioOHIO
On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the Rate Stabilization PlanRSP as modified and approved by the PUCO onin an August 4, 2004 Entry on Rehearing, subject to a competitive bid process.CBP. The Rate Stabilization PlanRSP was filed by the Ohio Companiesintended to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In the second quarter of 2004, the Ohio Companies implemented the accounting modifications related to the extended amortization periods and interest costs deferral on the deferred customer shopping incentive balances. On October 1 and October 4, 2004, the OCC and NOAC respectively, filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order andin this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming that order with respect to the approval of the rate stabilization charge, approval of the shopping credits, the grant of interest on shopping credit incentive deferral amounts, and approval of FirstEnergy’s financial separation plan. It remanded the approval of the RSP pricing back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient customer participation in the competitive marketplace.
The revised Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, and continues Under provisions of the RSP, the PUCO had required the Ohio Companies' supportCompanies to undertake a CBP to secure generation and allow for customer pricing participation in the competitive marketplace. Any acceptance of energy efficiencyfuture competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and economic development efforts. Other key components ofnot until 12 months after the revised Rate Stabilization Plan include the following:
· | extension of the transition cost amortization period for OE from 2006 to as late as 2007; for CEI from 2008 to as late as mid-2009 and for TE from mid-2007 to as late as mid-2008; |
· | deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and |
· | ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes. |
PUCO authorizes such termination. On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid processthe CBP for the generation supply period beginning January 1, 2006 and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan willRSP would take effect on January 1, 2006. On February 23, 2006 the CBP auction manager, National Economic Research Associates, notified the PUCO that a subsequent CBP to potentially provide firm generation service for the Ohio Companies' 2007 and 2008 actual load requirements could not proceed due to lack of interest, as there were no bidder applications submitted. Additionally, on March 20, 2006, the PUCO denied applications for rehearing filed by various parties regarding the PUCO's rules for the CBP. The above May 3, 2006 Supreme Court of Ohio opinion may require the PUCO to reconsider this customer pricing process.
On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies' RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:
| · | Maintaining the existing level of base distribution rates through December 31, 2008 for OE and TE, and April 30, 2009 for CEI; |
| · | Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years; |
| · | Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for OE and TE and as of December 31, 2010 for CEI; |
| · | Reducing the deferred shopping incentive balances as of January 1, 2006 by up to $75 million for OE, $45 million for TE, and $85 million for CEI by accelerating the application of each respective company's accumulated cost of removal regulatory liability; and |
| · | Recovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all OE and TE distribution and transmission customers through a fuel recovery mechanism. OE, TE, and CEI may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the amount collected through the fuel recovery mechanism (in lieu of implementation of the GCAF rider). |
The PUCO’s January 4, 2006 approval of the RCP also included approval of the Ohio Companies’ supplemental stipulation which was filed with the PUCO on November 4, 2005 and which was an additional component of the RCP filed on September 9, 2005. On January 10, 2006, the Ohio Companies filed a Motion for Clarification of the PUCO order approving the RCP. The Ohio Companies sought clarity on issues related to distribution deferrals, including requirements of the review process, timing for recognizing certain deferrals and definitions of the types of qualified expenditures. The Ohio Companies also sought confirmation that the list of deferrable distribution expenditures originally included in the revised stipulation fall within the PUCO order definition of qualified expenditures. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The PUCO may requiregranted the Ohio Companies’ requests to:
| · | Recognize fuel and distribution deferrals commencing January 1, 2006; | | | | | · | Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff; | | | | | · | Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and | | | | | · | Clarify that distribution expenditures do not have to be “accelerated” in order to be deferred. |
The PUCO approved the Ohio Companies’ methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies’ Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. The Ohio Companies responded to the applications for rehearing on February 13, 2006. In an Entry on Rehearing issued by the PUCO on March 1, 2006, all motions for rehearing were denied. Certain of these parties have subsequently filed their notices of appeal with the Supreme Court of Ohio alleging various errors made by the PUCO in its order approving the RCP.
On December 30, 2004, the Ohio Companies filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application sought recovery of these costs beginning January 1, 2006. The Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues expected to be recovered from January through June 30, 2006 are approximately $66 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. On May 1, 2006, the Ohio Companies filed a modification to the rider to determine revenues from July 2006 through June 2007.
The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to undertake, no more often than annually,defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of the Ohio Companies' case with a similar competitive bid process to secure generationcase involving Dayton Power & Light Company. Oral arguments are currently scheduled for May 10, 2006.
On January 20, 2006 the years 2007 and 2008. Any acceptanceOCC sought rehearing of future competitive bid results would terminate the Rate Stabilization Plan pricing, but not the related approved accounting, and not until twelve months after the PUCO authorizes such termination.approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The OCC's brief is expected to be filed during the second quarter of 2006. The briefs of the PUCO and the Ohio Companies will be due within thirty days of the OCC's filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On April 18, 2006, the Court denied both parts of the motion but on its own motion consolidated the OCC's appeal of the Ohio Companies' case with a similar case of Dayton Power & Light Company and stayed briefing on these appeals.
New JerseyPENNSYLVANIA
A February 2002 Commonwealth Court of Pennsylvania decision affirmed the June 2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanded the issues of quantification and allocation of merger savings to the PPUC and denied Met-Ed and Penelec the rate relief initially approved in the PPUC decision. On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In accordance with the PPUC's direction, Met-Ed and Penelec filed supplements to their tariffs that became effective in October 2003 and that reflected the CTC rates and shopping credits in effect prior to the June 2001 order.
Met-Ed’s and Penelec’s combined portion of total net merger savings during 2001 - 2004 is estimated to be approximately $51 million. A procedural schedule was established by the ALJ on January 17, 2006. The companies’ filed initial testimony on March 1, 2006. Hearings are currently scheduled for the end of October 2006 with the ALJ’s recommended decision to be issued in February 2007. The companies have requested that this proceeding be consolidated with the April 10, 2006 transition plan filing proceeding as discussed below. Met-Ed and Penelec are unable to predict the outcome of this proceeding.
In an October 16, 2003 order, the PPUC approved September 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also denied their accounting treatment request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse this PPUC finding; a Commonwealth Court judge subsequently denied their Objection on October 27, 2003 without explanation. On October 31, 2003, Met-Ed and Penelec filed an Application for Clarification of the Court order with the Commonwealth Court, a Petition for Review of the PPUC's October 2 and October 16, 2003 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. The Reargument Brief before the Commonwealth Court was filed on January 28, 2005. Oral arguments are scheduled for June 8, 2006.
As of March 31, 2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation are $328 million and $50 million, respectively. Penelec's $50 million is subject to the pending resolution of taxable income issues associated with NUG trust fund proceeds.
On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. As of March 31, 2006, the PPUC had taken no action on the request and neither company had yet implemented deferral accounting for these costs. Met-Ed and Penelec sought to consolidate this proceeding (and modified their request to provide deferral of 2006 transmission-related costs only) with the comprehensive rate filing they made on April 10, 2006 as described below. On May 4, 2006, the PPUC approved the modified request. Accordingly, Met-Ed and Penelec will implement deferral accounting for these costs in the second quarter of 2006, which will include $24 million and $4 million, respectively, representing the amounts that were incurred in the first quarter of 2006 -- the deferrals of such amounts will be reflected in the second quarter of 2006.
Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement. Under this 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 contracts with NUGs and other unaffiliated suppliers. The FES 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. The wholesale power sales agreement with FES could automatically be extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. On November 1, 2005, FES and the other parties thereto amended the agreement to provide FES the right in 2006 to terminate the agreement at any time upon 60 days notice. On April 7, 2006, the parties to the wholesale power sales agreement entered into a Tolling Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the wholesale power sales agreement effective midnight December 31, 2006, because that agreement is not economically sustainable to FES.
In lieu of allowing such termination to become effective as of December 31, 2006, the parties agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales agreement to provide as follows:
1.The termination provisions of the wholesale power sales agreement will be tolled for one year until December 31, 2007, provided that during such tolling period:
| a. | FES will be permitted to terminate the wholesale power sales agreement at any time with sixty days written notice; |
| b. | Met-Ed and Penelec will procure through arrangements other than the wholesale power sales agreement beginning December 1, 2006 and ending December 31, 2007, approximately 33% of the amounts of capacity and energy necessary to satisfy their PLR obligations for which Committed Resources (i.e., non-utility generation under contract to Met-Ed and Penelec, Met-Ed- and Penelec-owned generating facilities, purchased power contracts and distributed generation) have not been obtained; and |
| c. | FES will not be obligated to supply additional quantities of capacity and energy in the event that a supplier of Committed Resources defaults on its supply agreement. |
2.During the tolling period FES will not act as agent for Met-Ed or Penelec in procuring the services under section 1.(b) above; and
3.The pricing provision of the wholesale power sales agreement shall remain unchanged provided Met-Ed and Penelec comply with the provisions of the Tolling Agreement and any applicable provision of the wholesale power sales agreement.
In the event that FES elects not to terminate the wholesale power sales agreement effective midnight December 31, 2007, similar tolling agreements effective after December 31, 2007 are expected to be considered by FES for subsequent years if Met-Ed and Penelec procure through arrangements other than the wholesale power sales agreement approximately 64%, 83% and 95% of the additional amounts of capacity and energy necessary to satisfy their PLR obligations for 2008, 2009 and 2010, respectively, for which Committed Resources have not been obtained from the market.
The wholesale power sales agreement, as modified by the Tolling Agreement, requires Met-Ed and Penelec to satisfy the portion of their PLR obligations currently supplied by FES from unaffiliated suppliers at prevailing prices, which are likely to be higher than the current price charged by FES under the current agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. There can be no assurance, however, that if FES ultimately determines to terminate, or significantly modify the agreement, timely regulatory relief will be granted by the PPUC pursuant to the April 10, 2006 comprehensive rate filing discussed below, or, to the extent granted, adequate to mitigate such adverse consequences.
Met-Ed and Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 that addresses a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals is approved, the filing would increase annual revenues by $216 million and $157 million, respectively. That filing includes, among other things, a request to charge customers for an increasing amount of market priced power procured through a competitive bid process as the amount of supply provided under the existing FES agreement is phased out in accordance with the April 7, 2006 Tolling agreement described above. Met-Ed and Penelec also requested approval of the January 12, 2005 petition for the deferral of transmission-related costs discussed above, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider similar to that implemented in Ohio. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs are also included in the filing. The filing contemplates a reduction in distribution rates for Met-Ed in the amount of $37 million annually and an increase in distribution rates for Penelec in the amount of $20 million annually. Although the companies have proposed an effective date of June 10, 2006, it is expected that the PPUC will suspend the effective date for seven months as permitted under Pennsylvania law. Hearings are expected to be scheduled for the second half of 2006 and a PPUC decision is expected early in the first quarter of 2007.
On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn recommended that the RFP process cover the period January 1, 2007 through May 31, 2008. Hearings were held on January 10, 2006 with main briefs filed on January 27, 2006 and reply briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a Recommended Decision to adopt Penn's RFP process with modifications. The PPUC approved the Recommended Decision with additional modifications on April 20, 2006. The approved plan is designed to provide customers with PLR service for January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.
NEW JERSEY
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.NUGC rates and market sales of NUG energy and capacity. As of March 31, 2005,2006, the accumulated deferred cost balance totaled approximately $472$558 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval ofto securitize the securitization of theJuly 31, 2003 deferred balance. There can be no assuranceOn December 2, 2005, JCP&L filed a request for recovery of $165 million of actual above-market NUG costs incurred from August 1, 2003 through October 31, 2005 and forecasted above-market NUG costs for November and December 2005. On February 1, 2006, the NJBPU selected Bear Stearns as the financial advisor. Meetings with the NJBPU Staff and the DRA were held during March and April and additional discovery conducted. The DRA filed comments on April 6, 2006, arguing that the proposed securitization does not produce customer savings. JCP&L submitted reply comments on April 10, 2006. On February 23, 2006, JCP&L filed updated data reflecting actual amounts through December 31, 2005 of $154 million of cost incurred since July 31, 2003. The filing also includes a request for recovery of $49 million for above-market NUG costs incurred prior to August 1, 2003, to the extent if any, thatthose costs are not recoverable through securitization. On March 29, 2006, a pre-hearing conference was held with the NJBPU will permit such securitization.presiding ALJ. A schedule for the proceeding was established, including a discovery period and evidentiary hearings scheduled for September 2006.
The July 2003An NJBPU decision on JCP&L's base electric rate proceeding disallowed certain regulatory assets. JCP&L recorded charges to net income in 2003 for the disallowed costs aggregating $185 million ($109 net of tax). The subsequent NJBPU final decisionDecision and order issued in May 2004 resulted in JCP&L recording a $5.4 million reduction in 2004 of the estimated charges in 2003. The 2003 NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L's rate base. The decision orderedOrder approving a Phase II proceeding to review whether JCP&L is in compliance with current service reliabilityStipulation of Settlement and quality standards. The NJBPU also ordered that any expenditures and projects undertaken by JCP&L to increase its system's reliability be reviewed as partresolving the Motion for Reconsideration of the Phase II proceeding, to determine their prudence and reasonableness for rate recovery. In thatI Order was issued on May 31, 2005. The Phase II proceeding,Settlement includes a performance standard pilot program with potential penalties of up to 0.25% of allowable equity return. The Order requires that JCP&L file quarterly reliability reports (CAIDI and SAIFI information related to the performance pilot program) through December 2006 and updates to reliability related project expenditures until all projects are completed. The first quarterly report was submitted to NJBPU could increase JCP&L’s return on equity to 9.75% or decrease it to 9.25%, dependingAugust 16, 2005. The second quarterly report was submitted on its assessmentNovember 22, 2005. The third quarterly report as of the reliabilityDecember 31, 2005 was submitted on March 28, 2006. As of JCP&L's service. Any reduction would be retroactive to August 1, 2003. JCP&L filed an August 15, 2003 interim motion for rehearing and reconsideration with the NJBPU and a June 1, 2004 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 costs. Management is unable to predict when a decision may be reachedDecember 31, 2005 there were no performance penalties issued by the NJBPU.
On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for 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. The Ratepayer Advocate filed testimony on November 16, 2004, and JCP&L submitted rebuttal testimony on January 4, 2005. The Ratepayer Advocate surrebuttal testimony was submitted February 8, 2005. Discovery and settlement conferences are ongoing.
JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to an NJBPU order. New BGS tariffs reflecting the results of a February 2004 auctionorder for the BGS supply became effectiveperiod June 1, 2004. 2005 through May 31, 2006.
The auctionNJBPU decision approving the BGS procurement proposal for the supply period beginning June 1, 2006 was issued on October 12, 2005. JCP&L submitted a compliance filing on October 26, 2005, which was completedapproved on November 10, 2005. The written order was dated December 8, 2005. The auction took place in February 2005.2006. On February 9, 2006, the NJBPU approved the auction results and a written order was signed on February 23, 2006. The JCP&L tariff compliance filing was approved on March 29, 2006. New BGS rates become effective June 1, 2006.
In a reaction to the higher closing prices of the 2006 BGS fixed rate auction, the NJBPU, on March 16, 2006, initiated a generic proceeding to evaluate the auction process and potential options for the future. On April 6, 2006, initial comments were submitted. A public meeting was held on April 21, 2006 and a legislative-type hearing was held on April 28, 2006. Final comments were due on May 4, 2006. An NJBPU decision on the BGS post transition year three process 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.is anticipated in June 2006.
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 customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. 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. The Ratepayer AdvocateDRA filed comments on February 28, 2005.2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further proceedings has not yet been set.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the recent repeal of PUHCA under the EPACT. An NJBPU proposed rulemaking to address the issues was published in the NJ Register on December 19, 2005. The proposal would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. A public hearing was held February 7, 2006 and comments were submitted to the NJBPU. The NJBPU Staff issued a draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. Comments and reply comments are due by May 22 and May 31, 2006, respectively. JCP&L is not able to predict the outcome of this proceeding at this time. On December 21, 2005, the NJBPU initiated a generic proceeding and requested comments in order to formulate an appropriate regulatory treatment for investment tax credits related to generation assets divested by New Jersey’s four electric utility companies. Comments were filed by the utilities and by the DRA.
PennsylvaniaFERC MATTERS
A February 2002 Commonwealth Court of Pennsylvania decision affirmed the June 2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanded the issues of quantification and allocation of merger savings to the PPUC and denied Met-Ed and Penelec the rate relief initially approved in the PPUC decision. In October 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In accordance with the PPUC's direction, Met-Ed and Penelec filed supplements to their tariffs that were effective October 2003 and that reflected the CTC rates and shopping credits in effect prior to the June 2001 order.
In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. These companies' combined portion of total merger savings is estimated to be approximately $31.5 million. If no settlement can be reached, Met-Ed and Penelec will take the position that any portion of such savings should be allocated to customers during each company's next rate proceeding.
In response to their October 8, 2003 petition, the PPUC approved June 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC denied the accounting request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. Met-Ed and Penelec subsequently filed with the Commonwealth Court, on October 31, 2003, an Application for Clarification with the judge, 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. The Reargument Brief before the Commonwealth Court was filed January 28, 2005.
Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales 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. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and current market prices.
Transmission
On November 1, 2004, ATSI requested authority from thefiled with FERC a request to defer approximately $54 million of vegetation management costs ($14 million deferred as of March 31, 2005) estimated to be incurred from 2004 through 2007.2007 in connection with ATSI’s Vegetation Management Enhancement Project (VMEP), which represents ATSI’s adoption of newly identified industry “best practices” for vegetation management. On March 4, 2005, the FERC approved ATSI'sATSI’s request to defer those costs. ATSI expects to file an application with FERC in the first quarterVMEP costs (approximately $29 million deferred as of March 31, 2006). On March 28, 2006 for recovery of the deferred costs.
ATSI and MISO filed with the FERC on December 2, 2004, seeking approval for ATSIa request to have transmission rates established based on a FERC-approved cost of service - formula rate included inmodify ATSI’s Attachment O under the MISO tariff. The ATSI Network Service net revenue requirement increased under the formula rate to approximately $159 million. On Januaryinclude revenue requirements associated with recovery of deferred VMEP costs over a five-year period. The requested effective date to begin recovery is June 1, 2006. Various parties have filed comments responsive to the March 28, 2005,2006 submission. The FERC has not taken any action on the FERC accepted for filing the revised tariff sheets to become effective February 1, 2005, subject to refund, and ordered a public hearing be held to address the reasonablenessfiling. The estimated impact of the proposalVMEP cost recovery is $13 million in revenues annually during the five-year recovery period of June 1, 2006 to eliminate the voltage-differentiated rate design for the ATSI zone. On April 4, 2005, a settlement with all parties to the proceeding was filed with the FERC that provides for recovery of the full amount of the rate increase permitted under the formula.May 31, 2011.
On DecemberJanuary 24, 2006, ATSI and MISO filed with FERC a request to correct ATSI’s Attachment O formula rate to reverse revenue credits associated with termination of revenue streams from transitional rates stemming from FERC’s elimination of through and out rates. Revenues formerly collected under these rates were included in, and served to reduce, ATSI’s zonal transmission rate under the Attachment O formula. Absent the requested correction, elimination of these revenue streams would not be fully reflected in ATSI’s formula rate until June 1, 2008. On March 16, 2006, FERC approved without suspension the revenue credit correction, which became effective April 1, 2006. One party sought rehearing of the FERC's order. The FERC has not yet issued a further order. The estimated impact of the correction mechanism is approximately $40 million in revenues on an annualized basis beginning June 1, 2006. On November 18, 2004, the FERC issued an order eliminating the regional through and out rates (RTOR) for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within the MISO and PJM to submit compliance filings containing a mechanism - the Seams Elimination Cost Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be involved in the FERC hearings concerning the calculation and imposition of the SECA charges. The hearing began on May 1, 2006. The FERC has ordered the Presiding Judge to issue an initial decision by August 11, 2006. On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2004,2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order. On March 20, 2006 a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued an order approving this settlement on April 19, 2006. If the FERC accepts AEP's proposal, significant additional transmission revenues would be imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within PJM.
On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies filed an application withat a price equal to the retail generation rates approved by the PUCO seeking tariff adjustments to recover increasesfor a period of approximately $30 million in transmission and ancillary service coststhree years beginning January 1, 2006. The Ohio Companies also filedwill be relieved of their obligation to obtain PLR power requirements from FES if the Ohio competitive bid process results in a lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. The PPUC approved Penn's plan with modifications on April 20, 2006 to use an application for authorityRFP process to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ATSI rate increase, as applicable, from October 1, 2003 through December 31, 2005.obtain its power supply requirements after 2006.
On January 12, 2005, Met-Ed and Penelec filed a request with the PPUC for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $8 million per month.
Various parties have intervened in each of the cases above, and the Companies have not yet implemented deferral accounting for these costs.
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, Ohio. Under the FERC's decision, CEI may be responsible for a portion of new energy market charges imposed by 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. On April 15,December 29, 2005, the FERC issued an order on rehearing that "carves out" these contracts fromsetting the MISO Day 2 market. Whiletwo power sales agreements for hearing. The order criticized the order on rehearing is favorableOhio competitive bid process, and required FES to CEI, the impactsubmit additional evidence in support of the FERCreasonableness of the prices charged in the power sales agreements. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision on CEI is dependent upon many factors, includingto be issued in this case in late January 2007, as a result of an April 20, 2006 extension of the arrangements made by the cities for transmission service and MISO's ability to administer the contracts. Accordingly, the impactprocedural schedule. The outcome of this decisionproceeding cannot be determined at this time.predicted. FES has sought rehearing of the December 29, 2005 order and the FERC granted rehearing for further consideration on March 1, 2006.
Regulatory Assets
The EUOC recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations.
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 (OE - $250 million, CEI - $320 million, TE - $98 million, as of March 31, 2005) 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 during that period. OE, TE and CEI expect to recover these deferred customer shopping incentives by August 31, 2008, September 30, 2008 and August 31, 2010, respectively.
Regulatory transition costs as of March 31, 2005 for JCP&L, Met-Ed and Penelec are approximately $2.3 billion, $0.7 billion and $0.2 billion, respectively. Deferral of above-market costs from power supplied by NUGs to JCP&L are approximately $1.3 billion and are being recovered through BGS and MTC revenues. Met-Ed and Penelec have deferred above-market NUG costs totaling approximately $0.5 billion and $0.2 billion, respectively. These costs are being recovered through CTC revenues. The regulatory asset for above-market NUG costs and a corresponding liability are adjusted to fair value at the end of each quarter. Recovery of the remaining regulatory transition costs is expected to continue under the provisions of the various regulatory proceedings for New Jersey and Pennsylvania.
14.12. - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
FIN 47,“AccountingEITF Issue 04-13, "Accounting for Conditional Asset Retirement Obligations -Purchases and Sales of Inventory with the Same Counterparty"
In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an interpretationexchange of FASB Statement No. 143”inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, FirstEnergy will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. This EITF Issue will not have a material impact on FirstEnergy's financial results.
| SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140” |
On March 30, 2005, In February 2006, the FASB issued this interpretation to clarify the scopeSFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and timingHedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for theFinancial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an asset retirement obligationembedded derivative requiring bifurcation, clarifies that is conditionalconcentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient informationqualifying special-purpose entity from holding a derivative financial instrument that pertains to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed.a beneficial interest other than another derivative instrument. This InterpretationStatement is effective no later than the end of fiscal years ending after December 15, 2005.for all financial instruments acquired or issued beginning January 1, 2007. FirstEnergy is currently evaluating the effectimpact of this standard will haveStatement on its financial statements.
| SFAS 153,“Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”
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In December 2004, the FASB issued this Statement amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this statement are effective for nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. FirstEnergy is currently evaluating this standard but does not expect it to have a material impact on its financial statements.
SFAS 123 (revised 2004),“Share-Based Payment”
In December 2004, the FASB issued this revision to SFAS 123, which requires expensing stock options in the financial statements. Important to applying the new standard is understanding how to (1) measure the fair value of stock-based compensation awards and (2) recognize the related compensation cost for those awards. For an award to qualify for equity classification, it must meet certain criteria in SFAS 123(R). An award that does not meet those criteria will be classified as a liability and remeasured each period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensation. In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule results in a six-month deferral for FirstEnergy and other companies with a fiscal year beginning January 1. The Company will be applying modified prospective application, without restatement of prior interim periods. Any potential cumulative adjustments have not been determined. FirstEnergy uses the Black-Scholes option-pricing model to value options and will continue to do so upon adoption of SFAS 123(R).
| SFAS 151,“Inventory Costs - an amendment of ARB No. 43, Chapter 4”
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In November 2004, the FASB issued this statement to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be“so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by FirstEnergy after June 30, 2005. FirstEnergy is currently evaluating this standard but does not expect it to have a material impact on the financial statements.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
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.
| FSP 109-1,“Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction and Qualified Production Activities Provided by the American Jobs Creation Act of 2004”
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Issued in December 2004, FSP 109-1 provides guidance related to the provision within the American Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified production activities. The Act includes a tax deduction of up to 9 percent (when fully phased-in) of the lesser of (a)“qualified production activities income,” as defined in the Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). This tax deduction is limited to 50 percent of W-2 wages paid by the taxpayer. The FASB believes that the deduction should be accounted for as a special deduction in accordance with SFAS No. 109,“Accounting for Income Taxes.” FirstEnergy is currently evaluating this FSP but does not expect it to have a material impact on the Company's financial statements.
15.13. - SEGMENT INFORMATION:
FirstEnergy has threetwo reportable segments: regulated services and power supply management services (referred to as competitive electric energy services in previous filings) and facilities (HVAC) services. The aggregate“Other” “Other” segments do not individually meet the criteria to be considered a reportable segment. FirstEnergy's primary segment is itsThe regulated services segment, whosesegment's operations include the regulated sale of electricity and distribution and transmission services by its eight EUOCutility subsidiaries in Ohio, Pennsylvania and New Jersey. The power supply management services segment primarily consists of the subsidiaries (FES, FGCO, NGC and FENOC) that sell electricity in deregulated markets and operate and now own the generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation business.“Other” “Other” consists of telecommunications services, the recently sold MYR (a construction service company); and retail natural gas operations (recently sold - see(see Note 6) and telecommunications services.4). The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as“reportable “reportable segments.” The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems. Its revenues are primarily derived from electricity delivery and transition cost recovery. Assets of the regulated services segment includeas of March 31, 2005 included generating units that arewere leased or whose output had been sold to the power supply management services.services segment. The regulated services segment’s 2005 internal revenues representrepresented the rental revenues for the generating unit leases.leases which ceased in the fourth quarter of 2005 as a result of the intra-system generation asset transfers (see Note 14).
The power supply management services segment has responsibility for FirstEnergy generation operations. Itssupplies all of the electric power needs of FirstEnergy’s end-use customers through retail and wholesale arrangements, including regulated retail sales to meet the PLR requirements of FirstEnergy's Ohio and Pennsylvania companies and competitive retail sales to commercial and industrial businesses primarily in Ohio, Pennsylvania and Michigan. This business segment owns and operates FirstEnergy's generating facilities and purchases electricity from the wholesale market when needed to meet sales obligations. The segment's net income is primarily derived from all electric generation sales revenues which consist of generation services to regulated franchise customers who have not chosen an alternative generation supplier, retail sales in deregulated markets and all domestic unregulated electricity sales in the retail and wholesale markets less the related costs of electricity generation, including purchased power and sourcing of commodity requirements. Its net income also reflects the expense of the intersegment generating unit leases discussed abovetransmission, congestion and property tax amounts relatedancillary costs charged by PJM and MISO to those generating units.deliver energy to retail customers.
Segment reporting for interim periods in 20042005 was reclassified to conform withto the current year business segment organization and operations emphasizing FirstEnergy's regulated electric businesses and power supply management operations and the reclassification of discontinued operations (see Note 6)4). A previous reportableChanges in the current year operations reporting reflected in reclassifications of 2005 segment wasreporting primarily includes the more expansive competitivetransfer of the net results of retail transmission revenues and PJM/MISO transmission revenues and expenses associated with serving electricity load previously included in the regulated services segment whose aggregate operations consisted of FirstEnergy generation operations, natural gas commodity sales, providing local and long-distance phone service and other competitive energy-related businesses such as facilities services and construction service (MYR). Management's focus is on its core electric business. This has resulted in a change in performance review analysis from an aggregate view of all competitive services operations to a focus on itsthe power supply management services operations. During FirstEnergy's periodic reviewsegment. In addition, as a result of the 2005 Ohio tax legislation reducing the effective state income tax rate, the calculated composite income tax rate used in the two reportable segments under SFAS 131, that change resultedresults for 2005 and 2006 has been changed to 40% from the 41% previously reported in their 2005 segment results. The net amount of the changes in the revision of2005 reportable segments to the separate reporting of power supply management services and facilities services and including all other competitive services operationssegments' income taxes reclassifications has been correspondingly offset in the "Other" segment. Facilities services2005 "Reconciling Adjustments." FSG is being disclosed as a reporting segment due to theits subsidiaries qualifying as held for sale (see Note 6 for discussion of the divestiture of two of its subsidiaries in 2005).sale. Interest expense on holding company debt and corporate support services revenues and expenses are included in "Reconciling Items.Adjustments."
Segment Financial Information
| | | | | Power | | | | | | | | | | | | | | | | Supply | | | | | | | | | | | Segment Financial Information | | | | | Power | | | | | | | | | | | | | Regulated | | Management | | Facilities | | Reconciling | | | | | | | | | Supply | | | | | | | | | | | | | Services | | Services | | Services | | Other | | Adjustments | | Consolidated | | | Regulated | | Management | | Facilities | | | | Reconciling | | | | Three Months Ended | | (In millions) | | | Services | | Services | | Services | | Other | | Adjustments | | Consolidated | | | | | | (In millions) | | March 31, 2006 | | | | | | | | | | | | | | | | External revenues | | | $ | 1,083 | | $ | 1,619 | | $ | 46 | | $ | 120 | | $ | (23 | ) | $ | 2,845 | | | Internal revenues | | | | - | | - | | - | | - | | - | | - | | | Total revenues | | | | 1,083 | | 1,619 | | 46 | | 120 | | (23 | ) | | 2,845 | | | Depreciation and amortization | | | | 259 | | 46 | | - | | 1 | | 5 | | 311 | | | Investment Income | | | | 62 | | 15 | | - | | - | | (34 | ) | | 43 | | | Net interest charges | | | | 93 | | 49 | | - | | 1 | | 17 | | 160 | | | Income taxes | | | | 144 | | 27 | | - | | (7 | ) | | (30 | ) | | 134 | | | Net income | | | | 211 | | 40 | | (1 | ) | | 15 | | (44 | ) | | 221 | | | Total assets | | | | 23,848 | | 6,759 | | 63 | | 304 | | 823 | | 31,797 | | | Total goodwill | | | | 5,916 | | 24 | | - | | - | | - | | 5,940 | | | Property additions | | | | 195 | | 244 | | - | | 1 | | 7 | | 447 | | | | | | | | | | | | | | | | | | | March 31, 2005 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | External revenues | | $ | 1,339 | | $ | 1,295 | | $ | 56 | | $ | 112 | | $ | 11 | | $ | 2,813 | | | $ | 1,216 | | $ | 1,377 | | $ | 43 | | $ | 112 | | $ | 2 | | $ | 2,750 | | | Internal revenues | | | 78 | | -- | | -- | | -- | | (78 | ) | | -- | | | | 78 | | - | | - | | - | | (78 | ) | | - | | Total revenues | | | 1,417 | | 1,295 | | 56 | | 112 | | (67 | ) | | 2,813 | | | | 1,294 | | 1,377 | | 43 | | 112 | | (76 | ) | | 2,750 | | | Depreciation and amortization | | | 377 | | 10 | | -- | | 1 | | 6 | | 394 | | | | 374 | | 13 | | - | | 1 | | 6 | | 394 | | | Investment income | | | | 41 | | - | | - | | - | | - | | 41 | | | Net interest charges | | | 98 | | 10 | | -- | | 1 | | 62 | | 171 | | | | 98 | | 10 | | - | | 1 | | 62 | | 171 | | | Income taxes | | | 155 | | (25 | ) | | (3 | ) | | 10 | | (16 | ) | | 121 | | | | 157 | | (30 | ) | | (3 | ) | | 10 | | (13 | ) | | 121 | | | Income before discontinued operations | | | 223 | | (36 | ) | | (2 | ) | | 5 | | (49 | ) | | 141 | | | | 236 | | (46 | ) | | (2 | ) | | 5 | | (52 | ) | | 141 | | | Discontinued operations | | | -- | | -- | | 13 | | 6 | | -- | | 19 | | | | - | | - | | 13 | | 6 | | - | | 19 | | | Net income | | | 223 | | (36 | ) | | 11 | | 11 | | (49 | ) | | 160 | | | | 236 | | (46 | ) | | 11 | | 11 | | (52 | ) | | 160 | | | Total assets | | | 28,540 | | 1,582 | | 83 | | 495 | | 561 | | 31,261 | | | | 28,540 | | 1,582 | | 83 | | 495 | | 561 | | 31,261 | | | Total goodwill | | | 5,947 | | 24 | | -- | | 63 | | -- | | 6,034 | | | | 5,947 | | 24 | | - | | 63 | | - | | 6,034 | | | Property additions | | | 141 | | 81 | | 1 | | 2 | | 4 | | 229 | | | | 141 | | 81 | | 1 | | 2 | | 4 | | 229 | | | | | | | | | | | | | | | | | | | March 31, 2004 | | | | | | | | | | | | | | | | | External revenues | | $ | 1,290 | | $ | 1,522 | | $ | 58 | | $ | 116 | | $ | 11 | | $ | 2,997 | | | | Internal revenues | | | 79 | | -- | | -- | | -- | | (79 | ) | | -- | | | Total revenues | | | 1,369 | | 1,522 | | 58 | | 116 | | (68 | ) | | 2,997 | | | | Depreciation and amortization | | | 393 | | 9 | | 1 | | -- | | 9 | | 412 | | | | Net interest charges | | | 105 | | 11 | | -- | | 1 | | 54 | | 171 | | | | Income taxes | | | 145 | | (1 | ) | | (1 | ) | | 3 | | (31 | ) | | 115 | | | | Income before discontinued operations | | | 213 | | (2 | ) | | (1 | ) | | 5 | | (42 | ) | | 173 | | | | Discontinued operations | | | -- | | -- | | -- | | 1 | | -- | | 1 | | | | Net income | | | 213 | | (2 | ) | | (1 | ) | | 6 | | (42 | ) | | 174 | | | | Total assets | | | 29,336 | | 1,426 | | 167 | | 778 | | 878 | | 32,585 | | | | Total goodwill | | | 5,981 | | 24 | | 37 | | 75 | | -- | | 6,117 | | | | Property additions | | | 91 | | 44 | | 1 | | -- | | 2 | | 138 | | |
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses, fuel marketing revenues which(which are reflected as reductions to expenses for internal management reporting purposes,purposes) and elimination of intersegment transactions.
14. - FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS
On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred do not include leasehold interests of CEI, TE and OE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.
On October 24, 2005, the Ohio Companies and Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.
On December 16, 2005, the Ohio Companies and Penn completed the intra-system transfer of their respective ownership in the nuclear generation assets to NGC through, in the case of OE and Penn, an asset spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FENOC continues to operate and maintain the nuclear generation assets.
These transactions were pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.
JCP&L's earnings for the three months ended March 31, 2005 have been restated to reflect the results of a tax audit by the State of New Jersey, in which JCP&L became aware that the New Jersey Transitional Energy Facilities Assessment (TEFA) is not an allowable deduction for state income tax purposes. JCP&L had incorrectly claimed a state income tax deduction for TEFA payments and as a result, income taxes and interest expense were understated by $0.5 million and $0.6 million, respectively, in the first quarter of 2005. The effects of these adjustments on JCP&L's Consolidated Statements of Income for the three months ended March 31, 2005 are as follows:
| | | As Previously | | As | | | | Reported | | Restated | | | | (In millions) | | Operating Revenues | | $ | 529.1 | | $ | 529.1 | | Operating Expenses and | | | | | | | | Taxes | | | 494.7 | | | 495.2 | | Operating Income | | | 34.4 | | | 33.9 | | Net Interest Charges | | | 19.9 | | | 20.5 | | Net Income | | $ | 14.5 | | $ | 13.4 | | Earnings Applicable | | | | | | | | to Common Stock | | $ | 14.4 | | $ | 13.3 |
These adjustments were not material to FirstEnergy's consolidated financial statements, nor JCP&L's Consolidated Balance Sheets or Consolidated Statements of Cash Flows. FIRSTENERGY CORP. | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | March 31, | | | | | | | 2005 | | 2004 | | | | | | | | | | | | | (In thousands, except per share amounts) | REVENUES: | | | | | | | | | Electric utilities | | | | | $ | 2,308,516 | | $ | 2,177,033 | | | Unregulated businesses (Note 2) | | | | | | 504,196 | | | 819,505 | | Total revenues | | | | | | 2,812,712 | | | 2,996,538 | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | Fuel and purchased power (Note 2) | | | | | | 895,332 | | | 1,134,326 | | | Other operating expenses | | | | | | 905,388 | | | 812,642 | | | Provision for depreciation | | | | | | 142,632 | | | 145,850 | | | Amortization of regulatory assets | | | | | | 310,841 | | | 310,202 | | | Deferral of new regulatory assets | | | | | | (59,507 | ) | | (44,405 | ) | | General taxes | | | | | | 185,179 | | | 178,990 | | | Total expenses | | | | | | 2,379,865 | | | 2,537,605 | | | | | | | | | | | | | | INCOME BEFORE INTEREST AND INCOME TAXES | | | | | | 432,847 | | | 458,933 | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | Interest expense | | | | | | 164,657 | | | 172,510 | | | Capitalized interest | | | | | | (255 | ) | | (6,470 | ) | | Subsidiaries’ preferred stock dividends | | | | | | 6,553 | | | 5,281 | | | Net interest charges | | | | | | 170,955 | | | 171,321 | | | | | | | | | | | | | | INCOME TAXES | | | | | | 121,104 | | | 115,086 | | | | | | | | | | | | | | INCOME BEFORE DISCONTINUED OPERATIONS | | | | | | 140,788 | | | 172,526 | | | | | | | | | | | | | | | Discontinued operations (net of income taxes (benefit) of ($7,598,000) | | | | | | | | | | | | and $1,028,000, respectively) (Note 6) | | | | | | 18,938 | | | 1,473 | | | | | | | | | | | | | | NET INCOME | | | | | $ | 159,726 | | $ | 173,999 | | | | | | | | | | | | | | BASIC EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | | | | Income before discontinued operations | | | | | $ | 0.43 | | $ | 0.53 | | | Discontinued operations (Note 6) | | | | | | 0.06 | | | -- | | | Net income | | | | | $ | 0.49 | | $ | 0.53 | | | | | | | | | | | | | | WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING | | | | | | 327,908 | | | 327,057 | | | | | | | | | | | | | | DILUTED EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | | | | Income before discontinued operations | | | | | $ | 0.42 | | $ | 0.53 | | | Discontinued operations (Note 6) | | | | | | 0.06 | | | -- | | | Net income | | | | | $ | 0.48 | | $ | 0.53 | | | | | | | | | | | | | | WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING | | | | | | 329,427 | | | 329,034 | | | | | | | | | | | | | | DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | | | | | $ | 0.4125 | | $ | 0.375 | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral partof these statements. | | | | | | | | | | | | |
FIRSTENERGY CORP. | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME | | (Unaudited) | | | | | | | | | | | | Three Months Ended | | | | | March 31, | | | | | 2006 | | 2005 | | | | | (In millions, except per share amounts) | | REVENUES: | | | | | | | Electric utilities | | $ | 2,340 | | $ | 2,267 | | | Unregulated businesses | | | 505 | | | 483 | | | Total revenues | | | 2,845 | | | 2,750 | | | | | | | | | | | EXPENSES: | | | | | | | | | Fuel and purchased power | | | 976 | | | 895 | | | Other operating expenses | | | 893 | | | 884 | | | Provision for depreciation | | | 148 | | | 143 | | | Amortization of regulatory assets | | | 222 | | | 311 | | | Deferral of new regulatory assets | | | (59 | ) | | (60 | ) | | General taxes | | | 193 | | | 185 | | | Total expenses | | | 2,373 | | | 2,358 | | | | | | | | | | | OPERATING INCOME | | | 472 | | | 392 | | | | | | | | | | | OTHER INCOME (EXPENSE) | | | | | | | | | Investment income | | | 43 | | | 41 | | | Interest expense | | | (165 | ) | | (164 | ) | | Capitalized interest | | | 7 | | | - | | | Subsidiaries’ preferred stock dividends | | | (2 | ) | | (7 | ) | | Total other income (expense) | | | (117 | ) | | (130 | ) | | | | | | | | | | INCOME TAXES | | | 134 | | | 121 | | | | | | | | | | | INCOME BEFORE DISCONTINUED OPERATIONS | | | 221 | | | 141 | | | | | | | | | | | | Discontinued operations (net of income tax benefit of $8 million) | | | | | | | | | (Note 4) | | | - | | | 19 | | | | | | | | | | | NET INCOME | | $ | 221 | | $ | 160 | | | | | | | | | | | BASIC EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | Income before discontinued operations | | $ | 0.67 | | $ | 0.43 | | | Discontinued operations (Note 4) | | | - | | | 0.06 | | | Net income | | $ | 0.67 | | $ | 0.49 | | | | | | | | | | | WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING | | | 329 | | | 328 | | | | | | | | | | | DILUTED EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | Income before discontinued operations | | $ | 0.67 | | $ | 0.42 | | | Discontinued operations (Note 4) | | | - | | | 0.06 | | | Net income | | $ | 0.67 | | $ | 0.48 | | | | | | | | | | | WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING | | | 330 | | | 329 | | | | | | | | | | | DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | | $ | 0.45 | | $ | 0.4125 | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part | | | of these statements. | | | | | | | |
FIRSTENERGY CORP. | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | March 31, | | | | | | | | | | | | | | | | | | 2005 | | | | 2004 | | | | | | | | | | | | | | | | | | (In thousands) | | | | | | | | | | | | | NET INCOME | | | | | $ | 159,726 | | | | | $ | 173,999 | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | Unrealized gain on derivative hedges | | | | | | 7,323 | | | | | | 1,365 | | | Unrealized gain (loss) on available for sale securities | | | | | | (7,986 | ) | | | | | 16,938 | | | Other comprehensive income | | | | | | (663 | ) | | | | | 18,303 | | | Income tax related to other comprehensive income | | | | | | 129 | | | | | | (9,480 | ) | | Other comprehensive income (loss), net of tax | | | | | | (534 | ) | | | | | 8,823 | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME | | | | | $ | 159,192 | | | | | $ | 182,822 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integralpart of these statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
FIRSTENERGY CORP. | | | | | | | | | | | CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | | | | Three Months Ended | | | | | March 31, | | | | | 2006 | | | | 2005 | | | | | (In millions) | | NET INCOME | | $ | 221 | | | | | $ | 160 | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | Unrealized gain on derivative hedges | | | 43 | | | | | | 7 | | | Unrealized gain (loss) on available for sale securities | | | 36 | | | | | | (8 | ) | | Other comprehensive income (loss) | | | 79 | | | | | | (1 | ) | | Income tax expense related to other comprehensive income | | | 32 | | | | | | - | | | Other comprehensive income (loss), net of tax | | | 47 | | | | | | (1 | ) | | | | | | | | | | | | | COMPREHENSIVE INCOME | | $ | 268 | | | | | $ | 159 | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral | | | part of these statements. | | | | | | | | | | | | | | | | | | | | | | |
FIRSTENERGY CORP. | | | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | | | March 31, | | December 31, | | | | | | | 2005 | | 2004 | | | | | | | (In thousands) | | ASSETS | | | �� | | | | | CURRENT ASSETS: | | | | | | | | | Cash and cash equivalents | | | | | $ | 81,191 | | $ | 52,941 | | | Receivables- | | | | | | | | | | | | Customers (less accumulated provisions of $31,457,000 and | | | | | | | | | | | | $34,476,000, respectively, for uncollectible accounts) | | | | | | 983,488 | | | 979,242 | | | Other (less accumulated provisions of $32,807,000 and | | | | | | | | | | | | $26,070,000, respectively, for uncollectible accounts) | | | | | | 275,355 | | | 377,195 | | | Materials and supplies, at average cost- | | | | | | | | | | | | Owned | | | | | | 378,951 | | | 363,547 | | | Under consignment | | | | | | 98,917 | | | 94,226 | | | Prepayments and other | | | | | | 248,388 | | | 145,196 | | | | | | | | | 2,066,290 | | | 2,012,347 | | PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | In service | | | | | | 22,294,674 | | | 22,213,218 | | | Less - Accumulated provision for depreciation | | | | | | 9,479,701 | | | 9,413,730 | | | | | | | | | 12,814,973 | | | 12,799,488 | | | Construction work in progress | | | | | | 735,090 | | | 678,868 | | | | | | | | | 13,550,063 | | | 13,478,356 | | INVESTMENTS: | | | | | | | | | | | | Nuclear plant decommissioning trusts | | | | | | 1,604,062 | | | 1,582,588 | | | Investments in lease obligation bonds | | | | | | 918,632 | | | 951,352 | | | Other | | | | | | 734,419 | | | 740,026 | | | | | | | | | 3,257,113 | | | 3,273,966 | | DEFERRED CHARGES: | | | | | | | | | | | | Regulatory assets | | | | | | 5,606,433 | | | 5,532,087 | | | Goodwill | | | | | | 6,033,728 | | | 6,050,277 | | | Other | | | | | | 746,936 | | | 720,911 | | | | | | | | | 12,387,097 | | | 12,303,275 | | | | | | | | $ | 31,260,563 | | $ | 31,067,944 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | | | | Currently payable long-term debt | | | | | $ | 960,168 | | $ | 940,944 | | | Short-term borrowings | | | | | | 310,125 | | | 170,489 | | | Accounts payable | | | | | | 663,018 | | | 610,589 | | | Accrued taxes | | | | | | 687,341 | | | 657,219 | | | Other | | | | | | 1,022,302 | | | 929,194 | | | | | | | | | 3,642,954 | | | 3,308,435 | | CAPITALIZATION: | | | | | | | | | | | | Common stockholders’ equity- | | | | | | | | | | | | Common stock, $.10 par value, authorized 375,000,000 shares- | | | | | | | | | | | | 329,836,276 shares outstanding | | | | | | 32,984 | | | 32,984 | | | Other paid-in capital | | | | | | 7,058,484 | | | 7,055,676 | | | Accumulated other comprehensive loss | | | | | | (313,646 | ) | | (313,112 | ) | | Retained earnings | | | | | | 1,881,047 | | | 1,856,863 | | | Unallocated employee stock ownership plan common stock- | | | | | | | | | | | | 1,821,553 and 2,032,800 shares, respectively | | | | | | (37,916 | ) | | (43,117 | ) | | Total common stockholders' equity | | | | | | 8,620,953 | | | 8,589,294 | | | Preferred stock of consolidated subsidiaries | | | | | | 238,719 | | | 335,123 | | | Long-term debt and other long-term obligations | | | | | | 9,719,893 | | | 10,013,349 | | | | | | | | | 18,579,565 | | | 18,937,766 | | NONCURRENT LIABILITIES: | | | | | | | | | | | | Accumulated deferred income taxes | | | | | | 2,346,766 | | | 2,324,097 | | | Asset retirement obligations | | | | | | 1,095,105 | | | 1,077,557 | | | Power purchase contract loss liability | | | | | | 2,160,867 | | | 2,001,006 | | | Retirement benefits | | | | | | 1,255,077 | | | 1,238,973 | | | Lease market valuation liability | | | | | | 915,050 | | | 936,200 | | | Other | | | | | | 1,265,179 | | | 1,243,910 | | | | | | | | | 9,038,044 | | | 8,821,743 | | COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 12) | | | | | | | | | | | | | | | | | $ | 31,260,563 | | $ | 31,067,944 | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part ofthese balance sheets. | | | | | | | | | | | | |
FIRSTENERGY CORP. | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | March 31, | | December 31, | | | | | 2006 | | 2005 | | | | | (In millions) | | ASSETS | | | | | | | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 28 | | $ | 64 | | | Receivables - | | | | | | | | | Customers (less accumulated provisions of $37 million and | | | | | | | | | $38 million, respectively, for uncollectible accounts) | | | 1,072 | | | 1,293 | | | Other (less accumulated provisions of $27 million | | | | | | | | | for uncollectible accounts in both periods) | | | 154 | | | 205 | | | Materials and supplies, at average cost | | | 610 | | | 518 | | | Prepayments and other | | | 235 | | | 237 | | | | | | 2,099 | | | 2,317 | | PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | In service | | | 23,071 | | | 22,893 | | | Less - Accumulated provision for depreciation | | | 9,859 | | | 9,792 | | | | | | 13,212 | | | 13,101 | | | Construction work in progress | | | 1,073 | | | 897 | | | | | | 14,285 | | | 13,998 | | INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 1,818 | | | 1,752 | | | Investments in lease obligation bonds | | | 845 | | | 890 | | | Other | | | 805 | | | 765 | | | | | | 3,468 | | | 3,407 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 5,940 | | | 6,010 | | | Regulatory assets | | | 4,396 | | | 4,486 | | | Prepaid pension costs | | | 1,018 | | | 1,023 | | | Other | | | 591 | | | 600 | | | | | | 11,945 | | | 12,119 | | | | | $ | 31,797 | | $ | 31,841 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 2,115 | | $ | 2,043 | | | Short-term borrowings | | | 931 | | | 731 | | | Accounts payable | | | 612 | | | 727 | | | Accrued taxes | | | 803 | | | 800 | | | Other | | | 989 | | | 1,152 | | | | | | 5,450 | | | 5,453 | | CAPITALIZATION: | | | | | | | | | Common stockholders’ equity - | | | | | | | | | Common stock, $.10 par value, authorized 375,000,000 shares - | | | | | | | | | 329,836,276 shares outstanding | | | 33 | | | 33 | | | Other paid-in capital | | | 7,050 | | | 7,043 | | | Accumulated other comprehensive income (loss) | | | 27 | | | (20 | ) | | Retained earnings | | | 2,232 | | | 2,159 | | | Unallocated employee stock ownership plan common stock - | | | | | | | | | 1,167,865 and 1,444,796 shares, respectively | | | (22 | ) | | (27 | ) | | Total common stockholders' equity | | | 9,320 | | | 9,188 | | | Preferred stock of consolidated subsidiaries | | | 154 | | | 184 | | | Long-term debt and other long-term obligations | | | 8,004 | | | 8,155 | | | | | | 17,478 | | | 17,527 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 2,759 | | | 2,726 | | | Asset retirement obligations | | | 1,148 | | | 1,126 | | | Power purchase contract loss liability | | | 1,184 | | | 1,226 | | | Retirement benefits | | | 1,334 | | | 1,316 | | | Lease market valuation liability | | | 830 | | | 851 | | | Other | | | 1,614 | | | 1,616 | | | | | | 8,869 | | | 8,861 | | COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10) | | | | | | | | | | | $ | 31,797 | | $ | 31,841 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of | | | these balance sheets. | | | | | | | |
FIRSTENERGY CORP. | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | March 31, | | | | | | | 2005 | | 2004 | | | | | | | | | | | | | | | | (In thousands) | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | Net income | | | | | $ | 159,726 | | $ | 173,999 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | | | Provision for depreciation | | | | | | 142,632 | | | 145,850 | | | Amortization of regulatory assets | | | | | | 310,841 | | | 310,202 | | | Deferral of new regulatory assets | | | | | | (59,507 | ) | | (44,405 | ) | | Nuclear fuel and lease amortization | | | | | | 18,648 | | | 21,874 | | | Other amortization, net | | | | | | (5,451 | ) | | (4,723 | ) | | Deferred purchased power and other costs | | | | | | (109,233 | ) | | (83,907 | ) | | Deferred income taxes and investment tax credits, net | | | | | | (14,156 | ) | | 5,923 | | | Deferred rents and lease market valuation liability | | | | | | (35,663 | ) | | (16,297 | ) | | Accrued retirement benefit obligations | | | | | | 16,103 | | | 24,636 | | | Accrued compensation, net | | | | | | (41,722 | ) | | 4,387 | | | Commodity derivative transactions, net | | | | | | 187 | | | (30,787 | ) | | Income from discontinued operations (Note 6) | | | | | | (18,938 | ) | | (1,473 | ) | | Decrease (Increase) in operating assets: | | | | | | | | | | | | Receivables | | | | | | 90,663 | | | 272,746 | | | Materials and supplies | | | | | | 7,457 | | | 21,580 | | | Prepayments and other current assets | | | | | | (106,122 | ) | | (47,031 | ) | | Increase (Decrease) in operating liabilities: | | | | | | | | | | | | Accounts payable | | | | | | 61,419 | | | (177,018 | ) | | Accrued taxes | | | | | | 40,712 | | | 30,902 | | | Accrued interest | | | | | | 108,601 | | | 86,281 | | | Other | | | | | | 2,593 | | | (44,888 | ) | | Net cash provided from operating activities | | | | | | 568,790 | | | 647,851 | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | New Financing- | | | | | | | | | | | | Long-term debt | | | | | | -- | | | 581,558 | | | Short-term borrowings, net | | | | | | 139,811 | | | -- | | | Redemptions and Repayments- | | | | | | | | | | | | Preferred stock | | | | | | (97,900 | ) | | -- | | | Long-term debt | | | | | | (235,888 | ) | | (268,920 | ) | | Short-term borrowings, net | | | | | | -- | | | (387,541 | ) | | Net controlled disbursement activity | | | | | | (29,937 | ) | | (42,656 | ) | | Common stock dividend payments | | | | | | (135,306 | ) | | (122,465 | ) | | Net cash used for financing activities | | | | | | (359,220 | ) | | (240,024 | ) | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | Property additions | | | | | | (228,884 | ) | | (138,406 | ) | | Proceeds from asset sales | | | | | | 53,724 | | | 11,439 | | | Nonutility generation trust contributions | | | | | | -- | | | (50,614 | ) | | Contributions to nuclear decommissioning trusts | | | | | | (25,370 | ) | | (25,370 | ) | | Cash investments | | | | | | 26,904 | | | 20,218 | | | Other | | | | | | (7,694 | ) | | (58,800 | ) | | Net cash used for investing activities | | | | | | (181,320 | ) | | (241,533 | ) | | | | | | | | | | | | | | Net increase in cash and cash equivalents | | | | | | 28,250 | | | 166,294 | | | Cash and cash equivalents at beginning of period | | | | | | 52,941 | | | 113,975 | | | Cash and cash equivalents at end of period | | | | | $ | 81,191 | | $ | 280,269 | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part ofthese statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
FIRSTENERGY CORP. | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | Three Months Ended | | | | | March 31, | | | | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 221 | | $ | 160 | | | Adjustments to reconcile net income to net cash from operating activities - | | | | | | | | | Provision for depreciation | | | 148 | | | 143 | | | Amortization of regulatory assets | | | 222 | | | 311 | | | Deferral of new regulatory assets | | | (59 | ) | | (60 | ) | | Nuclear fuel and lease amortization | | | 20 | | | 19 | | | Deferred purchased power and other costs | | | (125 | ) | | (118 | ) | | Deferred income taxes and investment tax credits, net | | | 6 | | | (14 | ) | | Deferred rents and lease market valuation liability | | | (38 | ) | | (36 | ) | | Accrued compensation and retirement benefits | | | (19 | ) | | (26 | ) | | Commodity derivative transactions, net | | | 26 | | | 4 | | | Income from discontinued operations | | | - | | | (19 | ) | | Cash collateral | | | (106 | ) | | 2 | | | Decrease (Increase) in operating assets - | | | | | | | | | Receivables | | | 226 | | | 91 | | | Materials and supplies | | | (52 | ) | | 7 | | | Prepayments and other current assets | | | (15 | ) | | (106 | ) | | Increase (Decrease) in operating liabilities - | | | | | | | | | Accounts payable | | | (114 | ) | | 61 | | | Accrued taxes | | | 8 | | | 41 | | | Accrued interest | | | 100 | | | 108 | | | Electric service prepayment programs | | | (14 | ) | | (5 | ) | | Other | | | (33 | ) | | 35 | | | Net cash provided from operating activities | | | 402 | | | 598 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing - | | | | | | | | | Short-term borrowings, net | | | 200 | | | 140 | | | Redemptions and Repayments - | | | | | | | | | Preferred stock | | | (30 | ) | | (98 | ) | | Long-term debt | | | (64 | ) | | (236 | ) | | Net controlled disbursement activity | | | (8 | ) | | (30 | ) | | Common stock dividend payments | | | (148 | ) | | (135 | ) | | Net cash used for financing activities | | | (50 | ) | | (359 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (447 | ) | | (229 | ) | | Proceeds from asset sales | | | 57 | | | 54 | | | Proceeds from nuclear decommissioning trust fund sales | | | 481 | | | 366 | | | Investments in nuclear decommissioning trust funds | | | (484 | ) | | (391 | ) | | Cash investments | | | 25 | | | 27 | | | Other | | | (20 | ) | | (38 | ) | | Net cash used for investing activities | | | (388 | ) | | (211 | ) | | | | | | | | | | | Net increase (decrease) in cash and cash equivalents | | | (36 | ) | | 28 | | | Cash and cash equivalents at beginning of period | | | 64 | | | 53 | | | Cash and cash equivalents at end of period | | $ | 28 | | $ | 81 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of | | | these statements. | | | | | | | | | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors of FirstEnergy Corp.:
We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of March 31, 2005,2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 20052006 and 2004.2005. 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 as of December 31, 2004,2005, and the related consolidated statements of income, capitalization, common stockholders’ equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 20042005 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004;2005; 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 and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 2(K) and Note 12 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 March 7, 2005,February 27, 2006, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004,2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP Cleveland, Ohio May 3, 20058, 2006
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
EXECUTIVE SUMMARY
Net income in the first quarter of 20052006 was $221 million, or basic and diluted earnings of $0.67 per share of common stock, compared with net income of $160 million, or basic earnings of $0.49 per share of common stock ($0.48 diluted), compared to net income of $174 million, or basic and diluted earnings of $0.53 per share of common stock for the first quarter of 2004. During the quarter, FirstEnergy continued to divest non-core assets, including the sale of FirstEnergy’s retail natural gas business. These activities resulted in a combined net gain2005. Total revenues for the quarter of $0.07 per share of common stock.
The impact of costs associated with FirstEnergy’s settlement of the W. H. Sammis New Source Review (NSR) case and a proposed NRC fine related to the 2002 outage at the Davis-Besse nuclear power plant reduced earnings for the quarter by $0.05 per share of common stock. Also, nuclear operation and maintenance cost increases associated with the scheduled outages at the Davis-Besse and Perry nuclear power plants, combined with an unplanned outage at the Perry plant, reduced earnings per share by $0.12 compared with the first quarter of 2004.2006 were $2.84 billion, up from $2.75 billion as adjusted to reflect certain businesses divested in the first quarter of 2005. Certain businesses divested in the first quarter of 2005 have been classified as discontinued operations on the Consolidated Statements of Income (see Note 4). FirstEnergy’s earnings increase was driven primarily by increased electric sales revenues, reduced financing costs and reduced transition cost amortization for FirstEnergy's Ohio Companies.
Total electric generation KWH sales were up by 2.1 percent over the prior-year quarter, mostly due to the return of customers to the Ohio Companies from third-party suppliers leaving the Ohio marketplace. Electric distribution deliveries were down 2.6 percent during the same time period, reflecting milder weather conditions in 2006.
On March 18, 2005, FirstEnergy announced that it had reached FirstEnergy's generating fleet produced a settlement withrecord 20.1 billion KWH during the U.S. EPA, the U.S. Departmentfirst quarter of Justice, and three states that resolved all issues related2006 compared to various parties’ actions against FirstEnergy’s W. H. Sammis Plant18.8 billion KWH in the pending NSR case. The agreement, which isfirst quarter of 2005. FirstEnergy's non-nuclear fleet produced a record 13.4 billion KWH, while its nuclear facilities produced 6.7 billion KWH.
Ohio CBP - On February 23, 2006, the CBP auction manager, National Economic Research Associates, notified the PUCO that the CBP to potentially provide firm generation service for the Ohio Companies’ 2007 and 2008 actual load requirements could not proceed due to lack of interest, as there were no bidder applications submitted. Additionally, on March 16, 2006, the PUCO denied applications for rehearing filed by various parties regarding the PUCO’s rules for the CBP.
On May 3, 2006, the Supreme Court of Ohio, in the form of a consent decree, also was signedruling on certain appeals filed by the statesOCC and NOAC, issued an opinion affirming PUCO's June 2004 order with respect to the approval of Connecticut, New Jerseythe rate stabilization charge, approval of the shopping credits, the grant of interest on shopping credit incentive deferral amounts and New Yorkapproval of FirstEnergy's financial separation plan. It remanded the approval of the rate stabilization plan pricing back to the PUCO for further consideration of the issue as to whether the rate stabilization plan, as adopted by the PUCO, provided for sufficient customer participation.
Wind Power Generation - In March 2006, FirstEnergy entered into multi-year agreements to purchase a combined 330 MW of wind power output from three wind power generation projects. Two of the projects are being developed in West Virginia, and wasthe third is being developed in central Pennsylvania. The projects are anticipated to be complete and operational in 2007. When combined with prior contracts, these new contracts will bring the total wind power generation output available to FirstEnergy to 360 MW.
Pennsylvania Rate Matters - On April 10, 2006, FirstEnergy's subsidiaries, Met-Ed and Penelec, filed with the Court.PPUC a comprehensive transition rate plan. The filing addresses transmission, distribution and power supply issues while ensuring that customers continue to pay below-market prices for generation through 2010.
Met-Ed requested an overall revenue increase of $216 million, or 19 percent, for 2007 if its preferred approach of implementing accounting deferrals in its filing is approved. Under an alternative proposed approach, the 2007 increase could be up to $269 million, or 24 percent. Met-Ed also has proposed changes in its generation rates for the years 2008, 2009 and 2010 that could increase revenues by up to $165 million per year.
Penelec requested an overall revenue increase of $157 million, or 15 percent, for 2007 if its preferred approach of implementing accounting deferrals in its filing is approved. Under an alternative proposed approach that assumes accounting deferrals are not approved and instead adjusts rates to provide for appropriate cost recovery, the 2007 increase could be up to $206 million, or 19 percent. Penelec also has proposed changes in its generation rates for 2008, 2009 and 2010 that could increase revenues by up to $135 million per year.
Statutory generation rate caps imposed by Pennsylvania’s 1996 Electricity Generation Choice and Competition Act expired as of year-end 2005. While Met-Ed's and Penelec's 1998 restructuring plans implemented under that act contain additional price caps for generation through 2010, Met-Ed and Penelec also incorrectly anticipated that by mid-2003 they would only serve 20 percent of their PLR customers’ generation needs. However, Met-Ed and Penelec continue to serve virtually all of their PLR customers at these capped rates that have been and continue to be, well below market prices.
The transmission portion of each transition rate plan filed with the PPUC represents nearly one-half of the overall requested increase and reflects the pass-through of federally mandated charges for transmission services from PJM. Without regulatory relief, the charges Met-Ed and Penelec expect to pay in 2006 will exceed what they expect to collect from customers by an estimated $186 million (Met-Ed - $131 million; Penelec - $55 million).
With respect to the generation portion of customers' bills, the plan includes a four-year transition toward market-based generation rates. During this time, customers would continue paying below-market prices for power. Under the agreement, FirstEnergy will install environmental controls at all seven unitstransition plan, the market-priced portion of the Sammis Plant, as well as at othergeneration supply that Met-Ed and Penelec procure for customers would gradually increase through 2010.
The transition plan also proposes to defer, for future recovery, costs that Met-Ed and Penelec are required to incur under federal law for power plants. FirstEnergypurchased from NUGs for which there is currently inadequate recovery. The amount of these costs - above what Met-Ed and Penelec currently collect from customers - is expected to total approximately $92 million in 2006. However, the deferral would begin with costs incurred after new rates become effective.
Met-Ed and Penelec had filed on January 12, 2005 with the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005. As of March 31, 2006, the PPUC had taken no action on the request and neither company had yet implemented deferral accounting for these costs. Met-Ed and Penelec sought to consolidate this proceeding (and modified their request to provide deferral of 2006 transmission-related costs only) with the April 10, 2006 comprehensive rate filing. On May 4, 2006, the PPUC approved the modified request. Accordingly, Met-Ed and Penelec will also upgrade existing scrubber systems on units 1 through 3implement deferral accounting for these costs in the second quarter of its Bruce Mansfield Plant. Projects at the Sammis Plant2006, which will include equipment designed to reduce 95 percent$24 million and $4 million, respectively, representing the amounts were incurred in the first quarter of SO2 emissions and 90 percent2006 -- the deferrals of NOx emissions on the plant’s two largest units. Additionally, the plant’s five smaller unitssuch amounts will be controlled by equipment designed to reduce at least 50 percent of SO2 and 70 percent of NOx emissions. In total, additional environmental controls could be installed on nearly 5,500 MW of FirstEnergy’s 7,400 MW coal-based generating capacity, with construction beginning in 2005 and completed no later than 2012. The estimated $1.1 billion investment in environmental improvements is consistent with assumptions reflected in the Companies’ long-term financial planning.second quarter of 2006.
On March 15, 2005, membersNuclear Outages - Beaver Valley Unit 1 returned to service on April 19, 2006, restarting 11 days ahead of schedule from a refueling and maintenance outage. The unit was the first plant in the world to have a temporary opening cut in its containment building and have its steam generators and reactor head replaced within a 65-day time frame. The Beaver Valley Project also included replacing the turbine rotor, rewinding the main generator, and replacing approximately one-third of the International Brotherhood of Electrical Workers System Council U-3 ratified a new four-year contract with FirstEnergy subsidiary JCP&L. Ratificationfuel assemblies.
Davis-Besse returned to service on April 27, 2006 from an outage to refuel the plant and to modify it to generate more electricity. Work performed during the outage, which began on March 6, 2006, included refurbishing the plant's turbine and rebuilding two of the contract resolved issues surrounding health carefour reactor coolant pumps. Generating capacity is expected to increase by approximately 11 MW to a gross output of about 946 MW.
Penn RFP - On April 20, 2006 the PPUC approved Penn's PLR supply plan with modifications. The approved plan encourages wholesale electric suppliers to participate in an RFP process to provide customers with generation service from January 1, 2007, through May 13, 2008. Penn's PLR rates are currently capped at prices determined through restructuring agreements that are set to expire at the end of 2006. The PPUC is obligated to approve a PLR plan with rates that reflect prevailing market prices and work rules, and ended a 14-week strike against JCP&L by the Council’s members.that allow Penn to recover all reasonable costs for service.
FIRSTENERGY’S BUSINESS
FirstEnergy is a registered public utility holding company headquartered in Akron, Ohio that operates primarily through two core business segments.segments (see Results of Operations).
· | ·Regulated Services transmits and distributes electricity through FirstEnergy's eight utility operating companies that collectively comprise the nation’s fifth largest investor-owned electric system, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey. This business segment derives its revenue principally from the delivery of electricity generated or purchased by the Power Supply Management Services segment in the states in which the utility subsidiaries operate. transmit, distribute and sell electric power through eight electric utility operating companies that collectively 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. This business segment primarily derives its revenue from the delivery of electricity, including transition cost recovery. |
· | ·Power Supply ManagementServices supplies all of the electric power needs of end-use customers through retail and wholesale arrangements, including regulated retail sales to meet the PLR requirements of FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive retail sales to commercial and industrial businesses primarily in Ohio, Pennsylvania and Michigan. This business segment owns and operates FirstEnergy's generating facilities and purchases electricity from the wholesale market to meet sales obligations. The segment's net income is primarily derived from electric generation sales revenues less the related costs of electricity generation, including purchased power, and net transmission, congestion and ancillary costs charged by PJM and MISO to deliver energy to retail customers.Services supplies the power needs of end-use customers (principally in Ohio, Pennsylvania and New Jersey) through retail and wholesale arrangements, including sales to meet the PLR requirements of FirstEnergy’s Ohio Companies and Penn. This business operates the generating facilities of the Ohio Companies and Penn and purchases from the wholesale market to meet its sales obligations. It leases fossil facilities from the EUOC and purchases the entire output of the EUOC nuclear plants. This business segment principally derives its revenues from electric generation sales. |
Other operating segments provide a wide range of services, including heating, ventilation, air-conditioning, refrigeration, process piping, plumbing, electrical and facility control systems, high-efficiency electrotechnologies and telecommunication services. FirstEnergy continues to divest theseis in the process of divesting its remaining non-core businesses. Seebusinesses (see Note 6 to4). The assets and revenues for the consolidated financial statements.other business operations are below the quantifiable threshold for separate disclosure as “reportable operating segments”.
FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS 24
On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred do not include leasehold interests of CEI, TE and OE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.
On October 24, 2005, the Ohio Companies and Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.
On December 16, 2005, the Ohio Companies and Penn completed the intra-system transfer of their respective ownership in the nuclear generation assets to NGC through, in the case of OE and Penn, an asset spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FENOC continues to operate and maintain the nuclear generation assets.
These transactions were pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants. The transfers were intercompany transactions and, therefore, had no impact on our consolidated results.
RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among ourFirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 1513 to the consolidated financial statements. The FSG business segment is included in "Other“Other and Reconciling Adjustments"Adjustments” in this discussion due to its immaterial impact on current period financial results, but is presented separately in segment information provided in Note 1513 to the consolidated financial statements. Net income (loss) by major business segment was as follow:follows:
| | | Three Months Ended | | | | | Three Months Ended | | | | | | | March 31, | | Increase | | | March 31, | | Increase | | | | | 2005 | | 2004 | | (Decrease) | | | 2006 | | 2005 | | (Decrease) | | Net Income (Loss) | | (In millions) | | | (In millions, except per share data) | | By Business Segment | | | | | | | | | | | | | | | | Regulated services | | $ | 223 | | $ | 213 | | $ | 10 | | | $ | 211 | | $ | 236 | | $ | (25 | ) | | Power supply management services | | | (36 | ) | | (2 | ) | | (34 | ) | | | 40 | | | (46 | ) | | 86 | | | Other and reconciling adjustments* | | | (27 | ) | | (37 | ) | | 10 | | | | (30 | ) | | (30 | ) | | - | | | Total | | $ | 160 | | $ | 174 | | $ | (14 | ) | | $ | 221 | | $ | 160 | | $ | 61 | | | | | | | | | | | | | | | | | | | | | | | | Basic Earnings Per Share: | | | | | | | | | | | | | | | | | | | | | | Income before discontinued operations | | $ | 0.43 | | $ | 0.53 | | $ | (0.10 | ) | | $ | 0.67 | | $ | 0.43 | | $ | 0.24 | | | Discontinued operations | | $ | 0.06 | | $ | -- | | $ | 0.06 | | | | - | | | 0.06 | | | (0.06 | ) | | Net Income | | $ | 0.49 | | $ | 0.53 | | $ | (0.04 | ) | | $ | 0.67 | | $ | 0.49 | | $ | 0.18 | | | | | | | | | | | | | | | | | | | | | | | | Diluted Earnings Per Share: | | | | | | | | | | | | | | | | | | | | | | Income before discontinued operations | | $ | 0.42 | | $ | 0.53 | | $ | (0.11 | ) | | $ | 0.67 | | $ | 0.42 | | $ | 0.25 | | | Discontinued operations | | $ | 0.06 | | $ | -- | | $ | 0.06 | | | | - | | | 0.06 | | | (0.06 | ) | | Net Income | | $ | 0.48 | | $ | 0.53 | | $ | (0.05 | ) | | $ | 0.67 | | $ | 0.48 | | $ | 0.19 | |
* | * | Represents other operating segments and reconciling items including interest expense on holding company debt and corporate support services revenues and expenses. |
services revenues and expenses.31
Net income in the first quarter of 2005 included after-tax earnings from discontinued operations of $19 million ($0.06 per basic and diluted share) resulting from FirstEnergy’s disposition of non-core assets and operations. In the first quarter of 2005, discontinued operations included $17 million from net gains on sales (see“Other - First Quarter 2005 Compared to First Quarter 2004” below) and $2 million from operations.
In the first quarter of 2004, net income included $1 million2005, earnings were increased by $0.02 per share from discontinued operations.the combined impact of $0.07 per share of gains from the sale of non-core assets, offset by $0.04 per share of expense associated with the W. H. Sammis Plant New Source Review settlement and $0.01 per share of expense related to the fine by the Nuclear Regulatory Commission regarding the Davis-Besse Nuclear Power Station.
A decrease in wholesale electric revenues and purchased power costs in the first quarter of 2005 from the same period last year resulted from FES recording PJM sales and purchased power transactions on an hourly net position basis beginning in the first quarter of 2005 compared with recording each discrete transaction (on a gross basis) in the same period of 2004. This change had no impact on earnings and was caused by the dedication of FirstEnergy’s Beaver Valley Plant to PJM in January 2005. FirstEnergy believes that this economic change required a net presentation of revenues and purchased power transactions as these generation assets are now dedicated in PJM where FirstEnergy has third-party customers. Wholesale electric revenues and purchased power costs in the first quarter of 2004 each included $280 million of these transactions recorded on a gross basis.
Excluding the effect of recording the wholesale electric revenue transactions in PJM on a gross basis in 2004, first quarter 2005 operating revenues were modestly higher. Net income declined primarily due to increased nuclear production costs from refueling outages and the Sammis environmental settlement. Results for the first quarter of 2005 were enhanced by reduced employee benefit costs (see“Postretirement Plans” below), gains on the sale of assets and reduced fossil production costs.
Financial results for FirstEnergy and itsFirstEnergy's major business segments in the first quarter of 20052006 and 20042005 were as follows:
| | | | | Power | | | | | | | | | Power | | | | | | | | | | | Supply | | Other and | | | | | | | Supply | | Other and | | | | 1st Quarter 2005 | | Regulated | | Management | | Reconciling | | FirstEnergy | | | Financial Results | | Services | | Services | | Adjustments | | Consolidated | | | | | | (In millions) | | | Regulated | | Management | | Reconciling | | FirstEnergy | | First Quarter 2006 Financial Results | | | Services | | Services | | Adjustments | | Consolidated | | | | | | | | | | | | | | (In millions) | | | Revenue: | | | | | | | | | | | | Revenues: | | | | | | | | | | | External | | | | | | | | | | | | | | | | | | | Electric | | $ | 1,162 | | $ | 1,275 | | $ | -- | | $ | 2,437 | | | $ | 935 | | $ | 1,576 | | $ | - | | $ | 2,511 | | Other | | | 177 | | | 20 | | | 179 | | | 376 | | | | 148 | | | 43 | | | 143 | | | 334 | | Internal | | | 78 | | | -- | | | (78 | ) | | -- | | | | - | | | - | | | - | | | - | | | Total Revenues | | | 1,417 | | | 1,295 | | | 101 | | | 2,813 | | | | 1,083 | | | 1,619 | | | 143 | | | 2,845 | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | Fuel and purchased power | | | -- | | | 895 | | | -- | | | 895 | | | | - | | | 976 | | | - | | | 976 | | Other operating | | | 418 | | | 409 | | | 79 | | | 906 | | | | Other operating expenses | | | | 298 | | | 451 | | | 144 | | | 893 | | Provision for depreciation | | | 126 | | | 10 | | | 7 | | | 143 | | | | 96 | | | 46 | | | 6 | | | 148 | | Amortization of regulatory assets | | | 311 | | | -- | | | -- | | | 311 | | | | 222 | | | - | | | - | | | 222 | | Deferral of new regulatory assets | | | (60 | ) | | -- | | | -- | | | (60 | ) | | | (59 | ) | | - | | | - | | | (59 | ) | General taxes | | | 146 | | | 32 | | | 7 | | | 185 | | | | 140 | | | 45 | | | 8 | | | 193 | | | Total Expenses | | | 941 | | | 1,346 | | | 93 | | | 2,380 | | | | 697 | | | 1,518 | | | 158 | | | 2,373 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net interest charges | | | 98 | | | 10 | | | 63 | | | 171 | | | | Income taxes | | | 155 | | | (25 | ) | | (9 | ) | | 121 | | | | Operating Income (Loss) | | | | 386 | | | 101 | | | (15 | ) | | 472 | | | Other Income (Expense): | | | | | | | | | | | | | | | | Investment income | | | | 62 | | | 15 | | | (34 | ) | | 43 | | | Interest expense | | | | (94 | ) | | (53 | ) | | (18 | ) | | (165 | ) | | Capitalized interest | | | | 3 | | | 4 | | | - | | | 7 | | | Subsidiaries' preferred stock dividends | | | | (2 | ) | | - | | | - | | | (2 | ) | | Total Other Income (Expense) | | | | (31 | ) | | (34 | ) | | (52 | ) | | (117 | ) | | | | | | | | | | | | | | | | | | Income taxes (benefit) | | | | 144 | | | 27 | | | (37 | ) | | 134 | | | Income before discontinued operations | | | 223 | | | (36 | ) | | (46 | ) | | 141 | | | | 211 | | | 40 | | | (30 | ) | | 221 | | | Discontinued operations | | | -- | | | -- | | | 19 | | | 19 | | | | - | | | - | | | - | | | - | | | Net Income | | $ | 223 | | $ | (36 | ) | $ | (27 | ) | $ | 160 | | | | Net Income (Loss) | | | $ | 211 | | $ | 40 | | $ | (30 | ) | $ | 221 | |
| | | | | Power | | | | | | | | | | | Supply | | Other and | | | | 1st Quarter 2004 | | Regulated | | Management | | Reconciling | | FirstEnergy | | Financial Results | | Services | | Services | | Adjustments | | Consolidated | | | | | (In millions) | | | | | | | | | | | | | | Revenue: | | | | | | | | | | External | | | | | | | | | | Electric | | $ | 1,154 | | $ | 1,502 | | $ | -- | | $ | 2,656 | | Other | | | 136 | | | 20 | | | 185 | | | 341 | | Internal | | | 79 | | | -- | | | (79 | ) | | -- | | | Total Revenues | | | 1,369 | | | 1,522 | | | 106 | | | 2,997 | | | Expenses: | | | | | | | | | | | | | | Fuel and purchased power | | | -- | | | 1,134 | | | -- | | | 1,134 | | Other operating | | | 366 | | | 346 | | | 101 | | | 813 | | Provision for depreciation | | | 127 | | | 9 | | | 10 | | | 146 | | Amortization of regulatory assets | | | 310 | | | -- | | | -- | | | 310 | | Deferral of new regulatory assets | | | (44 | ) | | -- | | | -- | | | (44 | ) | General taxes | | | 147 | | | 25 | | | 7 | | | 179 | | | Total Expenses | | | 906 | | | 1,514 | | | 118 | | | 2,538 | | | | | | | | | | | | | | | | | | Net interest charges | | | 105 | | | 11 | | | 55 | | | 171 | | | Income taxes | | | 145 | | | (1 | ) | | (29 | ) | | 115 | | | Income before discontinued operations | | | 213 | | | (2 | ) | | (38 | ) | | 173 | | | Discontinued operations | | | -- | | | -- | | | 1 | | | 1 | | | Net Income | | $ | 213 | | $ | (2 | ) | $ | (37 | ) | $ | 174 | |
| | | | | Power | | | | | | | | | | | Supply | | Other and | | | | | | | Regulated | | Management | | Reconciling | | FirstEnergy | | First Quarter 2005 Financial Results | | Services | | Services | | Adjustments | | Consolidated | | | | | (In millions) | | | Revenues: | | | | | | | | | | | External | | | | | | | | | | | Electric | | $ | 1,082 | | $ | 1,355 | | $ | - | | $ | 2,437 | | | Other | | | 134 | | | 22 | | | 157 | | | 313 | | | Internal | | | 78 | | | - | | | (78 | ) | | - | | | Total Revenues | | | 1,294 | | | 1,377 | | | 79 | | | 2,750 | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | Fuel and purchased power | | | - | | | 895 | | | - | | | 895 | | | Other operating expenses | | | 324 | | | 503 | | | 57 | | | 884 | | | Provision for depreciation | | | 123 | | | 13 | | | 7 | | | 143 | | | Amortization of regulatory assets | | | 311 | | | - | | | - | | | 311 | | | Deferral of new regulatory assets | | | (60 | ) | | - | | | - | | | (60 | ) | | General taxes | | | 146 | | | 32 | | | 7 | | | 185 | | | Total Expenses | | | 844 | | | 1,443 | | | 71 | | | 2,358 | | | | | | | | | | | | | | | | | | Operating Income (Loss) | | | 450 | | | (66 | ) | | 8 | | | 392 | | | Other Income (Expense): | | | | | | | | | | | | | | | Investment income | | | 41 | | | - | | | - | | | 41 | | | Interest expense | | | (94 | ) | | (7 | ) | | (63 | ) | | (164 | ) | | Capitalized interest | | | 3 | | | (3 | ) | | - | | | - | | | Subsidiaries' preferred stock dividends | | | (7 | ) | | - | | | - | | | (7 | ) | | Total Other Income (Expense) | | | (57 | ) | | (10 | ) | | (63 | ) | | (130 | ) | | | | | | | | | | | | | | | | | Income taxes (benefit) | | | 157 | | | (30 | ) | | (6 | ) | | 121 | | | Income before discontinued operations | | | 236 | | | (46 | ) | | (49 | ) | | 141 | | | Discontinued operations | | | - | | | - | | | 19 | | | 19 | | | Net Income (Loss) | | $ | 236 | | $ | (46 | ) | $ | (30 | ) | $ | 160 | |
| | | | | Power | | | | | | | | | Power | | | | | | Change Between | | | | Supply | | Other and | | FirstEnergy | | | 1st Quarter 2005 and 2004 | | Regulated | | Management | | Reconciling | | Consolidated | | | Financial Results | | Services | | Services | | Adjustments | | Total | | | Change Between First Quarter 2006 and | | | | | Supply | | Other and | | | | First Quarter 2005 Financial Results | | | Regulated | | Management | | Reconciling | | FirstEnergy | | Increase (Decrease) | | (In millions) | | | Services | | Services | | Adjustments | | Consolidated | | | | | | | | | | | | | | (In millions) | | | Revenue: | | | | | | | | | | | | Revenues: | | | | | | | | | | | External | | | | | | | | | | | | | | | | | | | Electric | | $ | 8 | | $ | (227 | ) | $ | -- | | $ | (219 | ) | | $ | (147 | ) | $ | 221 | | $ | - | | $ | 74 | | Other | | | 41 | | | -- | | | (6 | ) | | 35 | | | | 14 | | | 21 | | | (14 | ) | | 21 | | Internal | | | (1 | ) | | -- | | | 1 | | | -- | | | | (78 | ) | | - | | | 78 | | | - | | | Total Revenues | | | 48 | | | (227 | ) | | (5 | ) | | (184 | ) | | | (211 | ) | | 242 | | | 64 | | | 95 | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | Fuel and purchased power | | | -- | | | (239 | ) | | -- | | | (239 | ) | | | - | | | 81 | | | - | | | 81 | | Other operating | | | 52 | | | 63 | | | (22 | ) | | 93 | | | | Other operating expenses | | | | (26 | ) | | (52 | ) | | 87 | | | 9 | | Provision for depreciation | | | (1 | ) | | 1 | | | (3 | ) | | (3 | ) | | | (27 | ) | | 33 | | | (1 | ) | | 5 | | Amortization of regulatory assets | | | 1 | | | -- | | | -- | | | 1 | | | | (89 | ) | | - | | | - | | | (89 | ) | Deferral of new regulatory assets | | | (16 | ) | | -- | | | -- | | | (16 | ) | | | 1 | | | - | | | - | | | 1 | | General taxes | | | (1 | ) | | 7 | | | -- | | | 6 | | | | (6 | ) | | 13 | | | 1 | | | 8 | | | Total Expenses | | | 35 | | | (168 | ) | | (25 | ) | | (158 | ) | | | (147 | ) | | 75 | | | 87 | | | 15 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net interest charges | | | (7 | ) | | (1 | ) | | 8 | | | -- | | | | Operating Income | | | | (64 | ) | | 167 | | | (23 | ) | | 80 | | | Other Income (Expense): | | | | | | | | | | | | | | | | Investment income | | | | 21 | | | 15 | | | (34 | ) | | 2 | | | Interest expense | | | | - | | | (46 | ) | | 45 | | | (1 | ) | | Capitalized interest | | | | - | | | 7 | | | - | | | 7 | | | Subsidiaries' preferred stock dividends | | | | 5 | | | - | | | - | | | 5 | | | Total Other Income (Expense) | | | | 26 | | | (24 | ) | | 11 | | | 13 | | | | | | | | | | | | | | | | | | | Income taxes | | | 10 | | | (24 | ) | | 20 | | | 6 | | | | (13 | ) | | 57 | | | (31 | ) | | 13 | | | Income before discontinued operations | | | 10 | | | (34 | ) | | (8 | ) | | (32 | ) | | | (25 | ) | | 86 | | | 19 | | | 80 | | | Discontinued operations | | | -- | | | -- | | | 18 | | | 18 | | | | - | | | - | | | (19 | ) | | (19 | ) | | Net Income | | $ | 10 | | $ | (34 | ) | $ | 10 | | $ | (14 | ) | | $ | (25 | ) | $ | 86 | | $ | - | | $ | 61 | |
Regulated Services - First Quarter 20052006 Compared to First Quarter 20042005 Net income increased to $223 million from $213decreased $25 million (or 5%10.6%) to $211 million in the first quarter of 2006 compared to $236 million in the first quarter of 2005, with increasedprimarily due to decreased operating revenues partially offset by higherlower operating expenses and taxes.
Revenues - -
The increasedecrease in total revenues resulted from the following sources:
| | | Three Months Ended | | | | | Three Months Ended | | | | Revenues | | March 31, | | Increase | | | By Type of Service | | 2005 | | 2004 | | (Decrease) | | | | | | (In millions) | | | March 31, | | Increase | | Revenues By Type of Service | | | 2006 | | 2005 | | (Decrease) | | | | | | | | | | | | (In millions) | | | Distribution services | | $ | 1,162 | | $ | 1,154 | | $ | 8 | | | $ | 935 | | $ | 1,082 | | $ | (147 | ) | | Transmission services | | | 92 | | | 62 | | | 30 | | | | 94 | | | 92 | | | 2 | | | Lease revenue from affiliates | | | 78 | | | 79 | | | (1 | ) | | | Internal revenues | | | | - | | | 78 | | | (78 | ) | | Other | | | 85 | | | 74 | | | 11 | | | | 54 | | | 42 | | | 12 | | | Total Revenues | | $ | 1,417 | | $ | 1,369 | | $ | 48 | | | $ | 1,083 | | $ | 1,294 | | $ | (211 | ) |
Changes Decreases in distribution deliveries by customer class are summarized in the following table:
| | Increase
| | Electric Distribution Deliveries | | (Decrease)
| | | Residential | | | (0.62.6 | )% | | Commercial | | | 4.7(2.1 | )% | | Industrial | | | 4.3(2.9 | )% | | Total Distribution Deliveries | | | (2.6 | )% |
Increased consumption offset The completion of the Ohio Companies' generation transition cost recovery under their respective transition plans and Penn's transition plan in part by2005 was the primary reason for lower distribution unit prices, which, in conjunction with lower KWH deliveries, resulted in higherlower distribution delivery revenue.revenues. The decreased deliveries to customers were primarily due to unseasonably mild weather during the first quarter of 2006. The following table summarizes major factors contributing to the $8$147 million increasedecrease in distribution service revenuerevenues in the first quarter of 2005:2006:
Sources of Change in Distribution Revenues | | | | Increase (Decrease) | | (In millions) | | | | | | | | Changes in customer usage | | $ | 23 | | | Changes in prices: | | | | | Rate changes -- | | | | | Ohio shopping incentive | | | (11 | ) | Other | | | 1 | | Rate mix & other | | | (5 | ) | | | | | | | | Net Increase in Distribution Revenues | | $ | 8 | |
Sources of Change in Distribution Revenues | | Decrease | | | | | (In millions) | | | Changes in customer usage | | $ | (5 | ) | | Changes in prices: | | | | | | Rate changes | | | (124 | ) | | Rate mix & other | | | (18 | ) | | | | | | | | Net Decrease in Distribution Revenues | | $ | (147 | ) |
Transmission The decrease in internal revenues reflected the effect of the generation asset transfers discussed above. The 2005 generation assets lease revenue from affiliates ceased as a result of the transfers. Other revenues increased $30$14 million in the first quarter of 2005 from the same period last year due in part to an amended power supply agreement with FES in June 2004. The amended agreement resulted in the regulated services segment assuming certain transmission revenues and expenses that were previously attributed to FES.
Other revenues increased $11 million primarily due to a paymenthigher payments received under a contract provision associated with the prior sale of TMI. Under the contract, additional payments are received if subsequent energy prices rise above specified levels. These payments are passed along to JCP&L, Met-Ed and Penelec customers, resulting in no net earnings effect. Other revenues were also impacted by an increase in customer late payment charges.
Expenses-
The higherdecrease in revenues discussed above werewas partially offset by the following increasesdecreases in total expenses:
· | Higher transmission expense of $43· | Other operating expenses were $26 million lower in 2006 due in part to an amended power supply agreement with FES, which also increased revenuethe following factors: |
1) The absence in 2006 of expenses for ancillary service refunds to third party suppliers of $7 million in 2005 due to the RCP, which provides that alternate suppliers of ancillary services now bill customers directly for those services;
| | 2) | The absence in 2006 of receivables factoring discount expenses of approximately $5 million incurred in 2005; and other operating costs |
3) A $4 million decrease in employee and contractor costs.
| · | Lower depreciation expense of $9 million;$27 million that resulted from the impact of the generation asset transfers. |
| · | Reduced amortization of regulatory assets of $89 million principally due to the completion of Ohio generation transition cost recovery and Penn's transition plan in 2005; and |
· | Increased income· | General taxes of $10decreased by $6 million primarily due to increased taxable income.lower property taxes as a result of the generation asset transfers. |
Partially offsetting these higher costs were two factors:Other Income -
· | Additional deferrals· | Higher investment income reflects the impact of regulatory assetsthe generation asset transfers. Interest income on the affiliated company notes receivable from the power supply management services segment in the first quarter of $16 million, primarily representing shopping incentives and interest on those deferrals;2006 is partially offset by the absence in 2006 of the majority of nuclear decommissioning trust income which is now included in the power supply management services segment; and |
· | Lower interest charges of $7· | Subsidiaries' preferred stock dividends decreased by $5 million primarilyin 2006 due to debt and preferred stock redemptions.redemption activity in 2005. |
Power Supply Management Services - First Quarter 20052006 Compared to First Quarter 20042005
The net loss Net income for this segment increased to $36was $40 million in the first quarter of 2005 from2006 compared to a net loss of $2$46 million in the same period last year. An improvement in the gross generation margin was more thanpartially offset by higher non-fuel nuclear costs,depreciation, general taxes and interest expense resulting infrom the increased net loss.
Generation Margin -
The gross generation margin in the first quarter of 2005 improved by $12 million compared to the same period of 2004, as shown in the table below.asset transfers.
Gross Generation Margin | | 2005 | | 2004 | | Increase (Decrease) | | | | | (In millions) | | | Electric generation revenue | | $ | 1,275 | | $ | 1,502 | | $ | (227 | ) | | Fuel and purchased power costs | | | 895 | | | 1,134 | | | (239 | ) | | Gross Generation Margin | | $ | 380 | | $ | 368 | | $ | 12 | |
Revenues - -
Excluding the effect of the change in recording PJM wholesale transactions,Electric generation sales revenues increased $53$199 million in the first quarter of 20052006 compared to the same period of 2004 asin 2005. This increase primarily resulted from a result of a 0.4%6.6% increase in retail KWH sales and higher unit prices.Additionalprices resulting from the 2006 rate stabilization and fuel recovery charges. Additional retail sales reduced energy available for sales to the wholesale market. The transmission revenues increase reflected new revenues under the MISO transmission rider of approximately $27 million that began in the first quarter of 2006.
A decrease An increase in reported segment revenues resulted from the following sources:
| | | Three Months Ended | | | | | Three Months Ended | | | | Revenues | | March 31, | | Increase | | | By Type of Service | | 2005 | | 2004 | | (Decrease) | | | | | | (In millions) | | | March 31, | | Increase | | Revenues By Type of Service | | | 2006 | | 2005 | | (Decrease) | | | | | | | | | | | | (In millions) | | | Electric Generation Sales: | | | | | | | | | | | | | | | Retail | | $ | 980 | | $ | 934 | | $ | 46 | | | $ | 1,239 | | $ | 980 | | $ | 259 | | Wholesale | | | 295 | | | 288 | | | 7 | | | | 235 | | | 295 | | | (60 | ) | | Total Electric Generation Sales | | | 1,275 | | | 1,222 | | | 53 | | | | 1,474 | | | 1,275 | | | 199 | | | Transmission | | | 10 | | | 16 | | | (6 | ) | | | Retail Transmission Rider | | | | 116 | | | 80 | | | 36 | | | Other Transmission | | | | 12 | | | 10 | | | 2 | | | Other | | | 10 | | | 4 | | | 6 | | | | 17 | | | 12 | | | 5 | | | Total | | | 1,295 | | | 1,242 | | | 53 | | | | PJM gross transactions | | | -- | | | 280 | | | (280 | ) | | | Total Revenues | | $ | 1,295 | | $ | 1,522 | | $ | (227 | ) | | $ | 1,619 | | $ | 1,377 | | $ | 242 | |
Changes The following table summarizes the price and volume factors contributing to changes in KWH sales are summarized in the following table:revenues from retail and wholesale customers:
| | | Increase | | Source of Change in Electric Generation Sales | | (Decrease) | | | | | (In millions) | | | Retail: | | | | | Effect of 6.6% increase in customer usage | | $ | 65 | | | Change in prices | | | 194 | | | | | | 259 | | | Wholesale: | | | | | Effect of 15.7% decrease in KWH sales | | | (46 | ) | Change in prices | | | (14 | ) | | | | | (60 | ) | | Net Increase in Electric Generation Sales | | $ | 199 | |
| | Increase
| | Electric Generation
| | (Decrease)
| | | | | | Retail | | | 1.2 | % | | | | | | Wholesale | | | (49.4 | )% | | | | | | Total Electric Generation | | | (15.9 | )%* |
*Increase of 0.4% excluding the effect of the PJM revision.Expenses - -
Excluding the effect of the $280 million of PJM purchased power costs recorded on a gross basis in 2004, total Total operating expenses net interest charges and income taxes increased by $87$75 million. The increase was due to the following factors:
| · | Higher fuel and purchased power costs of $41$81 million, which includeincluding increased fuel costs of $34$49 million, of which, coal costs, contributed $41 million as a result of increased generation output and higher coal prices reflecting higher transportation costs. The increase in coal transportation costs is primarily due to a change in the fuel mix resulting from a greater use of western coal. Purchased power costs, net of the Ohio RCP fuel deferral of $21 million, increased $32 million due to a greater reliance on higher cost fossil units duringprices partially offset by lower volume. Factors contributing to the nuclear refueling outages, and increased purchased powerhigher costs are summarized in the following table: |
| | | Increase | | Source of Change in Fuel and Purchased Power | | (Decrease) | | | | | (In millions) | | | Fuel: | | | | | Change due to increased unit costs | | $ | 32 | | Change due to volume consumed | | | 17 | | | | | | 49 | | | Purchased Power: | | | | | Change due to increased unit costs | | | 77 | | Change due to volume purchased | | | (33 | ) | Decrease in NUG costs deferred | | | 9 | | | | | | 53 | | | Ohio RCP fuel deferrals | | | (21 | ) | | | | | | | | Net Increase in Fuel and Purchased Power Costs | | $ | 81 | |
| · | Higher transmission expenses of $7 million;$30 million related to the transmission revenues discussed above; |
| · | Increased non-fuel nuclear costsdepreciation expenses of $66$33 million, due primarily to a refueling outage atwhich resulted principally from the Perry nuclear plant (including an unplanned extension), a scheduled 23-day mid-cycle inspection outage at the Davis-Besse nuclear plant in the first quarter of 2005 and the absence of nuclear scheduled outages in the same period last year; |
· | Accrual of an $8.5 million civil penalty payable to the Department of Justice and $10 million for obligations to three states in connection with the Sammis Plant settlement; |
· | Accrual of $3.5 million for a proposed NRC fine related to the 2002 Davis-Besse outage;generation asset transfers; and |
| · | Higher general taxes of $7$13 million due to additional gross receipts tax and payroll taxes.property taxes resulting from the generation asset transfers. |
Offsetting these higher costs were lower non-fuel operating expenses of $52 million, which reflect the absence in 2006 of generating asset lease rents of $78 million charged in 2005 due to the generation asset transfers. Also absent in 2006 were: (1) the 2005 accrual of an $8.5 million civil penalty payable to the DOJ and $10 million for obligations to fund environmentally beneficial projects in connection with the Sammis Plant settlement; and (2) a $3.5 million penalty related to the Davis-Besse outage.
Other Income - | · | Investment income in the first quarter of 2006 was higher by $15 million over the prior year period primarily due to nuclear decommissioning trust investments acquired through the generation asset transfers; and | | | | | · | Interest expense increased by $46 million, primarily due to the interest expense in 2006 on associated company notes payable used in connection with the generation asset transfers. This increase was partially offset by an additional $7 million of capitalized interest. |
Income Taxes - Income taxes increased as a result of higher taxable income.
Partially offsetting these amounts were the following factors:
· | Lower transmission costs of $26 million due in part to an amended power supply agreement that resulted in the regulated services segment assuming certain transmission obligations previously borne by the power supply management services segment; and |
· | Lower income taxes of $24 million due to lower taxable income. |
Other - First Quarter 20052006 Compared to First Quarter 20042005
FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a net improvement inno change to FirstEnergy’s net income in the first quarter of 20052006 compared to the same quarter of 2004.2005. The improvementeffect of lower income taxes due to allocations among the business segments offset the effect of the absence of the results of the 2005 discontinued operations. The 2005 results reflected the effect of discontinued operations, which included an after-tax net gain of $17 million from discontinued operations (see Note 6)4). The following table summarizes the sources of income from discontinued operations: Other - First Quarter 2005 Compared to First Quarter 2004
| | | Three Months Ended | | | | | March 31, | | | | | 2005 | | 2004 | | | | | (In millions) | | | Discontinued Operations (Net of tax) | | | | | | | Gain on sale: | | | | | | Natural gas business | | $ | 5 | | $ | -- | | Elliot-Lewis, Spectrum and Power Piping | | | 12 | | | -- | | | Reclassification of operating income | | | 2 | | | 1 | | | Total | | $ | 19 | | $ | 1 | |
Postretirement Plans
Pension costs were lower due to last year’s $500 million voluntary contribution and an increase in the market value of pension plan assets during 2004. Combined with amendments to FirstEnergy’s health care plan in the first quarter of 2004, employee benefit expenses decreased by $20 million in the first quarter of 2005 compared to the same period in 2004. The following table summarizes the net pension and OPEB expense (excluding amounts capitalized)operations for the three months ended March 31, 2005 and 2004.2005:
| | | Three Months Ended | | Postretirement Benefits Expense(1) | | March 31, | | | | | 2005 | | 2004 | | | | | (In millions) | | | | | | | | | | Pension | | $ | 8 | | $ | 20 | | | OPEB | | | 18 | | | 26 | | | Total | | $ | 26 | | $ | 46 | |
(1)Excludes the capitalized portion of postretirement benefits
costs (see Note 10 for total costs).
The decrease in pension and OPEB expenses are included in various cost categories and have contributed to other cost reductions discussed above.| | | (In millions) | | | Discontinued Operations (Net of tax) | | | | | Gain on sale: | | | | | Natural gas business | | $ | 5 | | | Elliot-Lewis, Spectrum and Power Piping | | | 12 | | | Reclassification of operating income | | | 2 | | | Total | | $ | 19 | |
CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy’s cash requirements in 2005 for operating expenses, construction expenditures, scheduled debt maturitiesDuring 2006 and preferred stock redemptions are expected to be met without increasing FirstEnergy’s net debt and preferred stock outstanding. Available borrowing capacity under credit facilities will be used to manage working capital requirements. Thereafter,thereafter, FirstEnergy expects to usemeet its contractual obligations primarily with a combination of cash from operations and funds from the capital markets. Borrowing capacity under credit facilities is available to manage working capital requirements.
Changes in Cash Position
TheFirstEnergy's primary source of ongoing cash required for FirstEnergy,continuing operations as a holding company is cash dividends from the operations of its subsidiaries. The holding companyFirstEnergy also has access to $1.375$2.0 billion of short-term financing under a revolving credit facilities.facility which expires in 2010, subject to short-term debt limitations under current regulatory approvals of $1.5 billion and to outstanding borrowings by subsidiaries of FirstEnergy that are also parties to such facility. In the first quarter of 2005,2006, FirstEnergy received $137$148 million of cash dividends from its subsidiaries and paid $135$148 million in cash dividends to its common shareholders. There are no material restrictions on the payment of cash dividends by FirstEnergy’sFirstEnergy's subsidiaries.
As of March 31, 2005,2006, FirstEnergy had $81$28 million of cash and cash equivalents ($3 million restricted as an indemnity reserve) compared with $53$64 million as of December 31, 2004.2005. The major sources for changes in these balances are summarized below.
Cash Flows From Operating Activities FirstEnergy's consolidated net cash from operating activities is provided primarily by its regulated services and power supply management services businesses (see“RESULTS OF OPERATIONS” Results of Operations above). Net cash provided from operating activities was $569$402 million in the first quarter of 2006 and $598 million in the first quarter of 2005, and $648 million in the first quarter of 2004, summarized as follows:
| | | Three Months Ended | | | | | March 31, | | Operating Cash Flows | | 2006 | | 2005 | | | | | (In millions) | | Cash earnings(1) | | $ | 388 | | $ | 359 | | | Working capital and other | | | 14 | | | 239 | | | Net cash provided from operating activities | | $ | 402 | | $ | 598 | |
| | | Three Months Ended | | | | | March 31, | | Operating Cash Flows | | 2005 | | 2004 | | | | | (In millions) | | | | | | | | | | | | | | | | Cash earnings(1) | | $ | 364 | | $ | 505 | | | Working capital and other | | | 205 | | | 143 | | | Total Cash Flows from Operating Activities | | $ | 569 | | $ | 648 | |
(1(1)) Cash earnings areis a non-GAAPNon-GAAP measure (see reconciliation below).
Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. FirstEnergy believes that cash earnings isare a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.
| | | Three Months Ended | | | Three Months Ended | | | | | March 31, | | | March 31, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | (In millions) | | | | | | | | | | | | | | | Net Income (GAAP) | | $ | 160 | | $ | 174 | | | $ | 221 | | $ | 160 | | | Non-Cash Charges (Credits): | | | | | | | | | | | | | | | | Provision for depreciation | | | 143 | | | 146 | | | | 148 | | | 143 | | | Amortization of regulatory assets | | | 311 | | | 310 | | | | 222 | | | 311 | | | Deferral of new regulatory assets | | | (60 | ) | | (44 | ) | | | (59 | ) | | (60 | ) | | Nuclear fuel and lease amortization | | | 19 | | | 22 | | | | 20 | | | 19 | | | Deferred purchased power and other costs | | | (109 | ) | | (84 | ) | | | (125 | ) | | (118 | ) | | Deferred income taxes and investment tax credits | | | (14 | ) | | 6 | | | | 6 | | | (14 | ) | | Deferred rents and lease market valuation liability | | | (36 | ) | | (16 | ) | | | (38 | ) | | (36 | ) | | Accrued compensation and retirement benefits | | | | (19 | ) | | (26 | ) | | Income from discontinued operations | | | (19 | ) | | (1 | ) | | | - | | | (19 | ) | | Other non-cash expenses | | | (31 | ) | | (8 | ) | | | 12 | | | (1 | ) | | Cash Earnings (Non-GAAP) | | $ | 364 | | $ | 505 | | | $ | 388 | | $ | 359 | |
The $141 Net cash provided from operating activities decreased by $196 million in the first quarter of 2006 compared to the first quarter of 2005 primarily due to a $225 million decrease in cash earnings is described under "RESULTS OF OPERATIONS". The working capital, increase primarily resulted from changes of $238 million in payables partially offset by a change$29 million increase in cash earnings described under "Results of $182Operations." The working capital decrease primarily resulted from increased outflows of $175 million for payables and $59 million for materials and supplies which reflected increased generation costs as discussed above and fuel inventory replacement activity due to increased fossil fuel consumption and higher unit prices; and $108 million of cash collateral returned to suppliers. These decreases were partially offset by an increase in receivables.cash provided from the settlement of receivables balances of $135 million which reflects increased electric sales revenues.
Cash Flows From Financing Activities
In the first quarters of 20052006 and 2004,2005, net cash used for financing activities of $359was $50 million and $240$359 million, respectively, primarily reflectedresulting from the redemptions of debt and preferred stock as shown below.
| | | Three Months Ended | | | | | March 31, | | Securities Issued or Redeemed | | 2006 | | 2005 | | | | | (In millions) | | Redemptions | | | | | | | | | FMB | | $ | - | | $ | 1 | | | Pollution control notes | | | 54 | | | - | | | Senior secured notes | | | 10 | | | 20 | | | Long-term revolving credit | | | - | | | 215 | | | Preferred stock | | | 30 | | | 98 | | | | | $ | 94 | | $ | 334 | | | | | | | | | | | | Short-term Borrowings, Net | | $ | 200 | | $ | 140 | |
| | | Three Months Ended | | | | | March 31, | | Securities Issued or Redeemed | | 2005 | | 2004 | | | | | (In millions) | | New Issues | | | | | | | Pollution control notes | | $ | -- | | $ | 185 | | | Senior notes | | | -- | | | 250 | | | Unsecured notes | | | -- | | | 147 | | | | | $ | -- | | $ | 582 | | Redemptions | | | | | | | | | First mortgage bonds | | $ | 1 | | $ | 92 | | | Secured notes | | | 20 | | | 42 | | | Long-term revolving credit | | | 215 | | | 135 | | | Preferred stock | | | 98 | | | -- | | | | | $ | 334 | | $ | 269 | | | | | | | | | | | | Short-term Borrowings, Net | | $ | 140 | | $ | (388 | ) |
FirstEnergy had approximately $310$931 million of short-term indebtedness as of March 31, 20052006 compared to approximately $170$731 million as of December 31, 2004.2005. This increase was due primarily to increased capital spending including the costs associated with the Davis-Besse and Beaver Valley Unit 1 refueling outages during the first quarter of 2006 and lower customer cash receipts. Available bank borrowing capability as of March 31, 20052006 included the following:
Borrowing Capability | | FirstEnergy | | OE | | Penelec | | Total | | | | | | | | (In millions) | | | (In millions) | | | Long-term revolving credit | | $ | 1,375 | | $ | 375 | | $ | -- | | $ | 1,750 | | | Short-term credit facilities(1) | | | $ | 2,120 | | | Accounts receivable financing facilities | | | | 550 | | | Utilized | | | -- | | | -- | | | -- | | | -- | | | | (919 | ) | | Letters of credit | | | (141 | ) | | -- | | | -- | | | (141 | ) | | | LOCs | | | | (116 | ) | | Net | | | 1,234 | | | 375 | | | -- | | | 1,609 | | | $ | 1,635 | | | | | | | | | | | | | | | | | | | | | | Short-term bank facilities | | | -- | | | 34 | | | 100 | | | 134 | | | | Utilized | | | -- | | | -- | | | (100 | ) | | (100 | ) | | | Net | | | -- | | | 34 | | | -- | | | 34 | | | | Total Unused Borrowing Capability | | $ | 1,234 | | $ | 409 | | $ | -- | | $ | 1,643 | | | (1) A $2 billion revolving credit facility that expires in 2010 is available in various amounts to FirstEnergy and certain of its subsidiaries. A $100 million revolving credit facility that expires in December 2006 and a $20 million uncommitted line of credit facility that expires in September 2006 are both available to FirstEnergy only. | | (1) A $2 billion revolving credit facility that expires in 2010 is available in various amounts to FirstEnergy and certain of its subsidiaries. A $100 million revolving credit facility that expires in December 2006 and a $20 million uncommitted line of credit facility that expires in September 2006 are both available to FirstEnergy only. |
As of March 31, 2005,2006, the Ohio Companies and Penn had the aggregate capability to issue approximately $4.3$1.3 billion 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 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 FMB) (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 $650$644 million and $565$576 million, respectively, as of March 31, 2005.2006. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of March 31, 2005,2006, JCP&L had the capability to issue $578$625 million of additional senior notes upon the basis of FMB collateral.
Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of $4.0$6 billion of preferred stock (assuming no additional debt was issued) as of March 31, 2005.2006. CEI, Met-Ed and Penelec do not have nosimilar restrictions onand could issue up to the issuancenumber of preferred stock.stock shares authorized under their respective charters.
As of March 31, 2005,2006, approximately $1.0$1 billion of capacity remained unused under FirstEnergy'san existing shelf registration statement, filed by FirstEnergy with the SEC in 2003, to support future securities issues.issuances. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units. As of April 26, 2006, a shelf registration statement filed by OE became effective and provides, together with previously effective OE registration statements, $1 billion of capacity to support future issuances of debt securities by OE.
FirstEnergy’sFirstEnergy's working capital and short-term borrowing needs are met principally with a syndicated $1$2 billion three-yearfive-year revolving credit facility maturing(included in the table above). Borrowings under the facility are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment expiration date, June 2007. Combined with FirstEnergy’s syndicated $375 million three-year16, 2010.
The following table summarizes the borrowing sub-limits for each borrower under the facility, maturing in October 2006, a $125 million three-year facility for OE maturing in October 2006,as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and a syndicated $250 million two-year facility for OE maturing in May 2005, primary syndicated credit facilities total $1.75 billion. Theseapplicable statutory and/or charter limitations:
| | | Revolving | | Regulatory and | | | | | Credit Facility | | Other Short-Term | | Borrower | | Sub-Limit | | Debt Limitations1 | | | | | (In millions) | | FirstEnergy | | $ | 2,000 | | $ | 1,500 | | OE | | | 500 | | | 500 | | Penn | | | 50 | | | 43 | | CEI | | | 250 | | | 500 | | TE | | | 250 | | | 500 | | JCP&L | | | 425 | | | 412 | | Met-Ed | | | 250 | | | 300 | | Penelec | | | 250 | | | 300 | | FES | | | -2 | | | n/a | | ATSI | | | -2 | | | 26 | |
| (2) | Borrowing sub-limits for FES and ATSI may be increased to up to $250 million and $100 million, respectively, by delivering notice to the administrative agent that either (i) such borrower has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed the obligations of such borrower under the facility. |
The revolving credit facilities,facility, combined with an aggregate $550 million ($292 million unused as of March 31, 2006) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet short-term working capital requirements for FirstEnergy and its subsidiaries.
Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under existing credit facilities and accounts receivable financing facilities totaled $1.9was $1.6 billion as of March 31, 2005.2006.
Borrowings under these facilities are conditioned on maintaining compliance with certainThe revolving credit facility contains financial covenants in the agreements. FirstEnergy and OE arerequiring each requiredborrower to maintain a consolidated debt to total capitalization ratio of no more than 0.65 to 1 and a contractually defined fixed charge coverage ratio65%, measured at the end of no less than 2 to 1. each fiscal quarter.
As of March 31, 2005, FirstEnergy’s2006, FirstEnergy and OE’s fixed charge coverage ratios, as defined under the credit agreements, were 4.47 to 1 and 6.87 to 1, respectively. FirstEnergy's and OE'sits subsidiaries' debt to total capitalization ratios as(as defined under the revolving credit agreements,facility) were 0.55 to 1 and 0.40 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, condition (financial or otherwise), results of operations, or prospects.as follows:
Borrower | | | | FirstEnergy | | | 54 | % | OE | | | 33 | % | Penn | | | 35 | % | CEI | | | 52 | % | TE | | | 31 | % | JCP&L | | | 27 | % | Met-Ed | | | 39 | % | Penelec | | | 36 | % |
Neither FirstEnergy's nor OE’s primaryThe revolving credit facilitiesfacility does not contain any provisions that either restrict theirthe ability to borrow or accelerate repayment of outstanding advances as a result of any change in their credit ratings. Each primary facility does contain "pricing grids"Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.
FirstEnergy’s FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’sFirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. For the regulated companies, available bank borrowings include $1.75 billion from FirstEnergy and OE’s revolving credit facilities. For the unregulated companies, available bank borrowings include only FirstEnergy’s $1.375 billion of revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of the 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 first quarter of 20052006 was 2.66%approximately 4.58% for both the regulated companies’ money pool and 2.68% for the unregulated companies' money pool.
On March 18, 2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affect FirstEnergy’s ratings or outlook. S&P noted that it continuesaccess to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspectioncapital markets and costs of financing are influenced by the NRC,ratings of its securities. The following table displays FirstEnergy’s and that if FirstEnergy should exit the outage without significant negative findings or delays theCompanies' securities ratings as of March 31, 2006. The ratings outlook would be revised tofrom S&P on all securities is stable. The ratings outlook from Moody's and Fitch on all securities is positive.
Issuer | | Securities | | S&P | | Moody’s | | Fitch | | | | | | | | | | FirstEnergy | | Senior unsecured | | BBB- | | Baa3 | | BBB- | | | | | | | | | | OE | | Senior unsecured | | BBB- | | Baa2 | | BBB | | | Preferred stock | | BB+ | | Ba1 | | BBB- | | | | | | | | | | CEI | | Senior secured | | BBB | | Baa2 | | BBB- | | | Senior unsecured | | BBB- | | Baa3 | | BB+ | | | | | | | | | | TE | | Senior secured | | BBB | | Baa2 | | BBB- | | | Preferred stock | | BB+ | | Ba2 | | BB | | | | | | | | | | Penn | | Senior secured | | BBB+ | | Baa1 | | BBB+ | | | Senior unsecured (1) | | BBB- | | Baa2 | | BBB | | | Preferred stock | | BB+ | | Ba1 | | BBB- | | | | | | | | | | JCP&L | | Senior secured | | BBB+ | | Baa1 | | BBB+ | | | Preferred stock | | BB+ | | Ba1 | | BBB- | | | | | | | | | | Met-Ed | | Senior secured | | BBB+ | | Baa1 | | BBB+ | | | Senior unsecured | | BBB | | Baa2 | | BBB | | | | | | | | | | Penelec | | Senior unsecured | | BBB | | Baa2 | | BBB |
(1)Penn's only senior unsecured debt obligations are notes underlying pollution control revenue refunding bonds issued by the Ohio Air Quality Development Authority to which bonds this rating applies.
On March 14, 2005, CEIJanuary 20, 2006, TE redeemed all 500,0001.2 million of its outstanding shares of its Serial Preferred Stock, $7.40 Series A at a price of $101 per share plus accrued dividends to the date of the redemption. Also on March 14, 2005, CEI redeemed all 474,000 outstanding shares of its Serial Preferred Stock, Adjustable Rate Series L at a price of $100 per share plus accrued dividends to the date of the redemption.
On May 16, 2005, Penn intends to redeem all 127,500 outstanding shares of 7.625%B preferred stock at $102.29 per share and all 250,000 outstanding shares of 7.75% preferred stock at $100 per share, both plus accrued dividends to the date of redemption.
On June 1, 2005, CEI intends to redeem all of its 40,000 outstanding shares of $7.35 Series C preferred stock at $101.00$25.00 per share, plus accrued dividends to the date of redemption.
On April 3, 2006, NGC issued pollution control revenue refunding bonds ($60 million at 3.07% and $46.5 million at 3.25%). These bonds were used to redeem the following Companies' pollution control notes (OE - $60 million at 7.05%, CEI - $27.7 million at 3.32%, TE - $18.8 million at 3.32%) on April 3, 2006. Also on April 3, 2006, FGCO issued pollution control revenue refunding bonds ($90.1 million at 3.03% and $56.6 million at 3.10%) which were used to redeem the following Companies' pollution control notes (OE - $14.8 million at 5.45%, Penn - $6.95 million at 5.45%, TE - $34.85 million at 3.18%, CEI - $47.5 million at 3.22%, $39.8 million at 3.20% and $2.8 million at 3.15%) in April and May 2006. These refinancings were undertaken in furtherance of FirstEnergy's intra-system generation asset transfers (see Note 14). The proceeds from NGC's and FGCO's refinancing issuances were used to repay a portion of their associated company notes payable to OE, Penn, CEI, and TE, who then redeemed their respective debt.
FirstEnergy will consider a common stock repurchase program later in 2006 after satisfactorily finalizing its environmental compliance plans for its fossil plants.
Cash Flows From Investing Activities
Net cash flows used in investing activities resulted principally from property additions. Regulated services expenditures for property additions primarily include expenditures supporting the distribution of electricity. Capital expenditures by the power supply management services segment are principally generation-related. The following table summarizes investments for the first quarter of 2006 and 2005 and 2004 investments by FirstEnergy’s regulated services, power supply management services and other segments:segment:
Summary of Cash Flows | | Property | | | | | | | | | Property | | | | | | | | Used for Investing Activities | | Additions | | Investments | | Other | | Total | | | Additions | | Investments | | Other | | Total | | 2005 First Quarter Sources (Uses) | | (In millions) | | | | | | | | | | | | | | | Sources (Uses) | | | (In millions) | | Three Months Ended March 31, 2006 | | | | | | | | | | | | Regulated services | | $ | (141 | ) | $ | 23 | | $ | 3 | | $ | (115 | ) | | $ | (195 | ) | $ | 58 | | $ | (7 | ) | $ | (144 | ) | | Power supply management services | | | (81 | ) | | (1 | ) | | -- | | | (82 | ) | | | (244 | ) | | (34 | ) | | - | | | (278 | ) | | Other | | | (3 | ) | | 16 | | | (13 | ) | | -- | | | | (1 | ) | | 16 | | | (5 | ) | | 10 | | | Reconciling items | | | (4 | ) | | 20 | | | -- | | | 16 | | | | Inter-Segment reconciling items | | | | (7 | ) | | 30 | | | 1 | | | 24 | | | Total | | $ | (229 | ) | $ | 58 | | $ | (10 | ) | $ | (181 | ) | | $ | (447 | ) | $ | 70 | | $ | (11 | ) | $ | (388 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2004 First Quarter Sources (Uses) | | | | | | | | | | | | | | | Three Months Ended March 31, 2005 | | | | | | | | | | | | | | | | Regulated services | | $ | (91 | ) | $ | (49 | ) | $ | (2 | ) | $ | (142 | ) | | $ | (141 | ) | $ | 21 | | $ | 3 | | $ | (117 | ) | | Power supply management services | | | (44 | ) | | (1 | ) | | -- | | | (45 | ) | | | (81 | ) | | 14 | | | - | | | (67 | ) | | Other | | | (1 | ) | | (7 | ) | | 2 | | | (6 | ) | | | (3 | ) | | 1 | | | (13 | ) | | (15 | ) | | Reconciling items | | | (2 | ) | | (27 | ) | | (20 | ) | | (49 | ) | | | Inter-Segment reconciling items | | | | (4 | ) | | (8 | ) | | - | | | (12 | ) | | Total | | $ | (138 | ) | $ | (84 | ) | $ | (20 | ) | $ | (242 | ) | | $ | (229 | ) | $ | 28 | | $ | (10 | ) | $ | (211 | ) |
Net cash used for investing activities in the first quarter of 20052006 increased by $177 million compared to the first quarter of 2005. The increase was $61 million lower compared with the same period of 2004. The decrease was primarilyprincipally due to higher proceedsa $218 million increase in property additions which reflects the replacement of $42 million from assets sales (see Note 6 to the consolidated financial statements),steam generators and reactor head at Beaver Valley Unit 1 and the absence of a $51 million NUG trust contributiondistribution system Accelerated Reliability Improvement Program. The increase in 2004 and increased other investment earnings,property additions was partially offset by a $91$22 million increasedecrease in property additions.net nuclear decommissioning trust activities due to completion of the Ohio Companies' and Penn's transition cost recovery for decommissioning at the end of 2005.
During the remaining three quarters of 2005,2006, capital requirements for property additions and capital leases are expected to be approximately $825 million, including $20 million for nuclear fuel.$860 million. FirstEnergy hasand the Companies have additional requirements of approximately $172 million to meet sinking fund requirements$1.3 billion for preferred stock and maturing long-term debt during the remainder of 2005.2006. These cash requirements are expected to be satisfied from a combination of internal cash, funds raised in the long-term debt capital markets and short-term credit arrangements.
FirstEnergy’sFirstEnergy's capital spending for the period 2005-20072006-2010 is expected to be about $3.3$6.7 billion (excluding nuclear fuel), of which $998 million$1.1 billion applies to 2005.2006. Investments for additional nuclear fuel during the 2005-2007 period2006-2010 periods are estimated to be approximately $274$769 million, of which approximately $53about $164 million applies to 2005.2006. During the same period, FirstEnergy’sFirstEnergy's nuclear fuel investments are expected to be reduced by approximately $280$574 million and $86$92 million, respectively, as the nuclear fuel is consumed.
GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. SuchThese agreements include contract guarantees, surety bonds, and LOCs. Some of the guaranteed contracts contain ratingscollateral provisions that are contingent collateralization provisions.upon FirstEnergy's credit ratings.
As of March 31, 2005, the2006, FirstEnergy's maximum exposure to potential future payments under outstanding guarantees and other assurances totaled $2.4approximately $3.3 billion, as summarized below:
| | | Maximum | | | Maximum | | Guarantees and Other Assurances | | Exposure | | | Exposure | | | | | (In millions) | | | | | | | | | (In millions) | | | FirstEnergy Guarantees of Subsidiaries: | | | | | | | Energy and Energy-Related Contracts(1) | | $ | 909 | | | $ | 906 | | Other(2) | | | 149 | | | | 884 | | | | | | 1,058 | | | | 1,790 | | | | | | | | | | | | | Surety Bonds | | | 267 | | | | 136 | | Letters of Credit(3)(4) | | | 1,059 | | | LOC(3)(4) | | | | 1,340 | | | | | | | | | | | | Total Guarantees and Other Assurances | | $ | 2,384 | | | $ | 3,266 | |
| | (1) | Issued for a one-year term,open-ended terms, with a 10-day termination right by FirstEnergy. |
| | (2) | Issued for various terms. |
| | (3) | Includes $141$116 million issued for various terms under LOC capacity available under FirstEnergy’srevolving FirstEnergy’s revolving credit agreement and $299$604 million outstanding in support
of pollution control revenue bondsissuedbonds issued with various maturities. |
| | (4) | Includes approximately $194 million pledged in connection with the sale and leaseback of Beaver ValleyUnitValley Unit 2 by CEI and TE, $291 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2by2 by OE and $134 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE. |
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy marketingcommodity 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 thoseits subsidiaries directly involved in these energy and energy-related transactions or financings where the law might otherwise limit the counterparties’counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’sFirstEnergy's guarantee enables the counterparty’scounterparty's legal claim to be satisfied by FirstEnergy’sFirstEnergy's other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related contracts is remote.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or“material “material adverse event”event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect asAs of March 31, 2005:2006, FirstEnergy's maximum exposure under these collateral provisions was $456 million.
| | | Total | | Collateral Paid | | Remaining | | Collateral Provisions | | Exposure | | Cash | | LOC | | Exposure(1) | | | | | (In millions) | | | | | | | | | | | | | | Credit rating downgrade | | $ | 364 | | $ | 153 | | $ | 18 | | $ | 193 | | | Adverse event | | | 42 | | | -- | | | 8 | | | 34 | | | Total | | $ | 406 | | $ | 153 | | $ | 26 | | $ | 227 | |
| (1) | As of May 2, 2005, FirstEnergy’s total exposure decreased to $357 million and the remaining exposure decreased to
$183 million - net of $148 million of cash collateral and $26 million of LOC collateral provided to counterparties.
|
Most of FirstEnergy’sFirstEnergy'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.
FirstEnergy has guaranteed the obligations of the operators of the TEBSA project up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC (currently at $47 million)($36 million as of March 31, 2006), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.
OFF-BALANCE SHEET ARRANGEMENTS
FirstEnergy has obligations that are not included on its Consolidated Balance SheetSheets related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are reflected as part of thesatisfied through operating lease payments. The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.4$1.3 billion as of March 31, 2005.
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 $142 million of off-balance sheet financing as of March 31, 2005.2006.
FirstEnergy has equity ownership interests in certain various businesses that are accounted for using the equity method. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations are disclosed under contractual obligationsGuarantees and Other Assurances 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’sFirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company.
Commodity Price Risk
FirstEnergy is exposed to financial and market riskrisks resulting from the fluctuation of interest rates and commodity prices primarily due to fluctuatingfluctuations in electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowance prices. To manage the volatility relating to these exposures, itFirstEnergy 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.All derivatives Derivatives that fall within the scope of SFAS 133 must be recorded at their fair market value and be marked to market. The majority of FirstEnergy’sFirstEnergy's derivative hedging contracts qualify for the normal purchasespurchase and normal salessale exception under SFAS 133 exemption and are therefore excluded from the table below. Of those contractsContracts that are not exempt from such treatment most areinclude power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts that do not qualifyare adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for hedge accounting treatment.Most of FirstEnergy’s non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133.above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 20052006 is summarized in the following table:
Increase (Decrease) in the Fair Value of Commodity Derivative Contracts | | | | | | | | | Non-Hedge | | Hedge | | Total | | | | | Non-Hedge | | Hedge | | Total | | | (In millions) | | | | | (In millions) | | | | | | | | | | | | | Change in the Fair Value of Commodity Derivative Contracts: | | | | | | | | | | | | | | | | Outstanding net asset as of January 1, 2005 | | $ | 62 | | $ | 2 | | $ | 64 | | | | Outstanding net liability as of January 1, 2006 | | | $ | (1,170 | ) | $ | (3 | ) | $ | (1,173 | ) | | New contract value when entered | | | -- | | | -- | | | -- | | | | - | | | - | | | - | | | Additions/change in value of existing contracts | | | (1 | ) | | 6 | | | 5 | | | | 122 | | | (7 | ) | | 115 | | | Change in techniques/assumptions | | | -- | | | -- | | | -- | | | | - | | | - | | | - | | | Settled contracts | | | (7 | ) | | 1 | | | (6 | ) | | | (81 | ) | | 5 | | | (76 | ) | | Sale of retail natural gas contracts | | | 1 | | | (6 | ) | | (5 | ) | | | | | | | | | | | | | | | | | | | | | | | | Outstanding net asset as of March 31, 2005(1) | | $ | 55 | | $ | 3 | | $ | 58 | | | Outstanding net liability as of March 31, 2006(1) | | | $ | (1,129 | ) | $ | (5 | ) | $ | (1,134 | ) | | | | | | | | | | | | | | | | | | | | | | | Non-commodity Net Assets as of March 31, 2005: | | | | | | | | | | | | Non-commodity Net Assets as of March 31, 2006: | | | | | | | | | | | | Interest Rate Swaps(2) | | | -- | | | (27 | ) | | (27 | ) | | | - | | | (16 | ) | | (16 | ) | Net Assets - Derivatives Contracts as of March 31, 2005 | | $ | 55 | | $ | (24 | ) | $ | 31 | | | Net Liabilities - Derivatives Contracts as of March 31, 2006 | | | $ | (1,129 | ) | $ | (21 | ) | $ | (1,150 | ) | | | | | | | | | | | | | | | | | | | | | | | Impact of Changes in Commodity Derivative Contracts:(3) | | | | | | | | | | | | | | | | | | | | | | Income Statement Effects (Pre-Tax) | | $ | -- | | $ | -- | | $ | -- | | | $ | (2 | ) | $ | - | | $ | (2 | ) | | Balance Sheet Effects: | | | | | | | | | | | | | | | | | | | | | | Other Comprehensive Income (Pre-Tax) | | $ | -- | | $ | 1 | | $ | 1 | | | $ | - | | $ | (2 | ) | $ | (2 | ) | | Regulatory Liability | | $ | (7 | ) | $ | -- | | $ | (7 | ) | | Regulatory Asset (net) | | | $ | (43 | ) | $ | - | | $ | (43 | ) |
(1) Includes $54$1,140 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory liability.asset. (2) Interest rate swaps are treated as cash flow or fair value hedges. Changes in derivative values are offset by changes in the hedged debts' premium or discounthedges (see Interest Rate Swap Agreements below).
(3) Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.
Derivatives are included on the Consolidated Balance Sheet as of March 31, 20052006 as follows:
Balance Sheet Classification | | Non-Hedge | | Hedge | | Total | | | Non-Hedge | | Hedge | | Total | | | | | (In millions) | | | (In millions) | | Current- | | | | | | | | | | | | | | | Other assets | | $ | -- | | $ | 2 | | $ | 2 | | | $ | 5 | | $ | 12 | | $ | 17 | | Other liabilities | | | (1 | ) | | -- | | | (1 | ) | | | (9 | ) | | (15 | ) | | (24 | ) | | | | | | | | | | | | | | | | | | | | | | | Non-Current- | | | | | | | | | | | | | | | | | | | | | Other deferred charges | | | 56 | | | 2 | | | 58 | | | | 46 | | | 30 | | | 76 | | Other noncurrent liabilities | | | -- | | | (28 | ) | | (28 | ) | | | (1,171 | ) | | (48 | ) | | (1,219 | ) | | | | | | | | | | | | | | | | | | | | | | | Net assets | | $ | 55 | | $ | (24 | ) | $ | 31 | | | | Net assets (liabilities) | | | $ | (1,129 | ) | $ | (21 | ) | $ | (1,150 | ) |
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:
Source of Information | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | —Fair Value by Contract Year | | 2005(1) | | 2006 | | 2007 | | 2008 | | 2009 | | Thereafter | | Total | | | | | | (In millions) | | | - Fair Value by Contract Year | | | 2006(1) | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter | | Total | | | | | | | | | | | | | | | | | | | | (In millions) | | Prices actively quoted(2) | | $ | 5 | | $ | 2 | | $ | 1 | | $ | -- | | $ | -- | | $ | -- | | $ | 8 | | | $ | (2 | ) | $ | (2 | ) | $ | - | | $ | - | | $ | - | | $ | - | | $ | (4 | ) | Sale of retail natural gas contracts(2) | | | (4 | ) | | (1 | ) | | -- | | -- | | -- | | �� | -- | | (5 | ) | | Other external sources(3) | | | 11 | | 10 | | -- | | -- | | -- | | -- | | 21 | | | | (281 | ) | | (284 | ) | | - | | | - | | | - | | | - | | | (565 | ) | | Prices based on models | | | -- | | | -- | | | 10 | | | 9 | | | 7 | | | 8 | | | 34 | | | | - | | | - | | | (246 | ) | | (166 | ) | | (137 | ) | | (16 | ) | | (565 | ) | | | | | | | | | | | | | | | | | | | | Total(4) | | $ | 12 | | $ | 11 | | $ | 11 | | $ | 9 | | $ | 7 | | $ | 8 | | $ | 58 | | | $ | (283 | ) | $ | (286 | ) | $ | (246 | ) | $ | (166 | ) | $ | (137 | ) | $ | (16 | ) | $ | (1,134 | ) |
(1) For the last three quarters of 2005.2006. (2) Exchange traded. (3) Broker quote sheets. (4)Includes $54 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. | (4) | Includes $1,140 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset. |
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 nontradingits derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of March 31, 2005.2006. Based on derivative contracts held as of March 31, 2005,2006, an adverse 10% change in commodity prices would decrease net income by approximately $1$5 million forduring the next twelve12 months. Interest Rate Swap AgreementsAgreements- Fair Value Hedges
FirstEnergy utilizes fixed-to-floatingfixed-for-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk ofassociated with its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues-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. During the first quarter of 2005,2006, FirstEnergy executed two new interest rateunwound swaps with a total notional amount of $50$350 million for which FirstEnergy paid $1 million in cash. The loss will be recognized over the remaining maturity of each ($100 million total notional amount) on underlying EUOC and FirstEnergy senior notes with an average fixed rate of 6.51%.respective hedged security as increased interest expense. As of March 31, 2005,2006, the debt underlying the $1.75 billion$750 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.59%5.74%, which the swaps have effectively converted to a current weighted average variable interest rate of 4.32%6.24%.
| | | March 31, 2006 | | December 31, 2005 | | | | | Notional | | Maturity | | Fair | | Notional | | Maturity | | Fair | | Interest Rate Swaps | | Amount | | Date | | Value | | Amount | | Date | | Value | | | | | (In millions) | | | (Fair value hedges) | | $ | 100 | | | 2008 | | $ | (4 | ) | $ | 100 | | | 2008 | | $ | (3 | ) | | | | | 50 | | | 2010 | | | (1 | ) | | 50 | | | 2010 | | | - | | | | | - | | | 2011 | | | - | | | 50 | | | 2011 | | | - | | | | | | 300 | | | 2013 | | | (12 | ) | | 450 | | | 2013 | | | (4 | ) | | | | | 150 | | | 2015 | | | (13 | ) | | 150 | | | 2015 | | | (9 | ) | | | | | - | | | 2016 | | | - | | | 150 | | | 2016 | | | - | | | | | | 50 | | | 2025 | | | (2 | ) | | 50 | | | 2025 | | | (1 | ) | | | | | 100 | | | 2031 | | | (8 | ) | | 100 | | | 2031 | | | (5 | ) | | | | $ | 750 | | | | | $ | (40 | ) | $ | 1,100 | | | | | $ | (22 | ) |
Forward Starting Swap Agreements - Cash Flow Hedges
FirstEnergy utilizes forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 2006 through 2008. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first quarter of 2006, FirstEnergy entered into forward swaps with a total notional amount of $525 million and terminated forward swaps with a total notional amount of $500 million from which FirstEnergy received $16 million in cash. The gain associated with the ineffective portion of the terminated hedges ($5 million) was recognized in earnings in the first quarter of 2006, with the remainder to be recognized over the terms of the respective forward swaps. As of March 31, 2006, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $1 billion and an aggregate fair value of $25 million.
Interest Rate Swaps
| | | March 31, 2005 | | December 31, 2004 | | | | | Notional | | Maturity | | Fair | | Notional | | Maturity | | Fair | | Denomination | | Amount | | Date | | Value | | Amount | | Date | | Value | | | | | (Dollars in millions) | | | Fixed to Floating Rate | | | | | | | | | | | | | | (Fair value hedges) | | $ | 200 | | | 2006 | | $ | (3 | ) | $ | 200 | | | 2006 | | $ | (1 | ) | | | | | 100 | | | 2008 | | | (3 | ) | | 100 | | | 2008 | | | (1 | ) | | | | | 100 | | | 2010 | | | (2 | ) | | 100 | | | 2010 | | | 1 | | | | | | 100 | | | 2011 | | | -- | | | 100 | | | 2011 | | | 2 | | | | | | 450 | | | 2013 | | | (7 | ) | | 400 | | | 2013 | | | 4 | | | | | | 100 | | | 2014 | | | -- | | | 100 | | | 2014 | | | 2 | | | | | | 150 | | | 2015 | | | (9 | ) | | 150 | | | 2015 | | | (7 | ) | | | | | 200 | | | 2016 | | | (2 | ) | | 200 | | | 2016 | | | 1 | | | | | | 150 | | | 2018 | | | 3 | | | 150 | | | 2018 | | | 5 | | | | | | 50 | | | 2019 | | | 2 | | | 50 | | | 2019 | | | 2 | | | | | | 150 | | | 2031 | | | (6 | ) | | 100 | | | 2031 | | | (4 | ) | | | | $ | 1,750 | | | | | $ | (27 | ) | $ | 1,650 | | | | | $ | 4 | |
| | | March 31, 2006 | | December 31, 2005 | | | | | Notional | | Maturity | | Fair | | Notional | | Maturity | | Fair | | Forward Starting Swaps | | Amount | | Date | | Value | | Amount | | Date | | Value | | | | | (In millions) | | | (Cash flow hedges) | | $ | 25 | | | 2015 | | $ | 1 | | $ | 25 | | | 2015 | | $ | - | | | | | | 250 | | | 2016 | | | 8 | | | 600 | | | 2016 | | | 2 | | | | | | 50 | | | 2017 | | | 1 | | | 25 | | | 2017 | | | - | | | | | | 125 | | | 2018 | | | 4 | | | 275 | | | 2018 | | | 1 | | | | | | 50 | | | 2020 | | | 2 | | | 50 | | | 2020 | | | - | | | | | | 500 | | | 2036 | | | 9 | | | - | | | 2036 | | | - | | | | | $ | 1,000 | | | | | $ | 25 | | $ | 975 | | | | | $ | 3 | |
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $956 million and $951 million$1.1 billion as of March 31, 20052006 and December 31, 2004, respectively.2005. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $96$113 million reduction in fair value as of March 31, 2005.2006.
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 aggressively 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 March 31, 2005,2006, the largest credit concentration was with one party currently(currently rated investment grade, thatgrade) represented 7%7.1% of FirstEnergy's total credit risk. Within itsFirstEnergy's unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserve,reserves, were with investment-grade counterparties as of March 31, 2005.2006.
Outlook
State Regulatory Matters
In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Companies' respective state regulatory plans. These provisions include:
| · | restructuring the electric generation business and allowing the Companies' customers to select a competitive electric generation supplier other than the Companies; | | | | | · | establishing or defining the PLR obligations to customers in the Companies' service areas; | | | | | · | providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; | | | | | · | itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; | | | | | · | continuing regulation of the Companies' transmission and distribution systems; and | | | | | · | requiring corporate separation of regulated and unregulated business activities. |
The EUOCCompanies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatoryRegulatory assets are expected to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations.
Regulatory Assets* | | March 31, | | December 31, | | Increase | | | | | 2005 | | 2004 | | (Decrease) | | | | | (In millions) | | | OE | | $ | 1,022 | | $ | 1,116 | | $ | (94 | ) | | CEI | | | 925 | | | 959 | | | (34 | ) | | TE | | | 349 | | | 375 | | | (26 | ) | | JCP&L | | | 2,268 | | | 2,176 | | | 92 | | | Met-Ed | | | 750 | | | 693 | | | 57 | | | Penelec | | | 278 | | | 200 | | | 78 | | | ATSI | | | 14 | | | 13 | | | 1 | | | Total | | $ | 5,606 | | $ | 5,532 | | $ | 74 | |
*Penn had net regulatory liabilities ofdo not earn a current return totaled approximately $27$237 million and $18 million included in Noncurrent
Liabilities on the Consolidated Balance Sheet as of March 31, 20052006. The following table discloses the regulatory assets by company and December 31, 2004, respectively.by source:
| | | March 31, | | December 31, | | Increase | | Regulatory Assets* | | 2006 | | 2005 | | (Decrease) | | | | | (In millions) | | | OE | | $ | 757 | | $ | 775 | | $ | (18 | ) | | CEI | | | 858 | | | 862 | | | (4 | ) | | TE | | | 276 | | | 287 | | | (11 | ) | | JCP&L | | | 2,168 | | | 2,227 | | | (59 | ) | | Met-Ed | | | 308 | | | 310 | | | (2 | ) | | ATSI | | | 29 | | | 25 | | | 4 | | | Total | | $ | 4,396 | | $ | 4,486 | | $ | (90 | ) |
| * | Penn had net regulatory liabilities of approximately $64 million and $59 million as of March 31, 2006 and December 31, 2005. Penelec had net regulatory liabilities of approximately $156 million and $163 million as of March 31, 2006 and December 31, 2005. These net regulatory liabilities are included in Other Noncurrent Liabilities on the Consolidated Balance Sheets. |
Regulatory assets by source are as follows:
Regulatory Assets By Source | | March 31, | | December 31, | | Increase | | | | | 2005 | | 2004 | | (Decrease) | | | | | (In millions) | | | Regulatory transition costs | | $ | 4,881 | | $ | 4,889 | | $ | (8 | ) | | Customer shopping incentives* | | | 668 | | | 612 | | | 56 | | | Customer receivables for future income taxes | | | 296 | | | 246 | | | 50 | | | Societal benefits charge | | | 40 | | | 51 | | | (11 | ) | | Loss on reacquired debt | | | 87 | | | 89 | | | (2 | ) | | Employee postretirement benefits costs | | | 62 | | | 65 | | | (3 | ) | | Nuclear decommissioning, decontamination | | | | | | | | | | | and spent fuel disposal costs | | | (163 | ) | | (169 | ) | | 6 | | | Asset removal costs | | | (345 | ) | | (340 | ) | | (5 | ) | | Property losses and unrecovered plant costs | | | 45 | | | 50 | | | (5 | ) | | Other | | | 35 | | | 39 | | | (4 | ) | | Total | | $ | 5,606 | | $ | 5,532 | | $ | 74 | |
*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 $668 million as
of March 31, 2005 (OE - $250 million, CEI - $320 million, TE - $98 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 during that period.| | | March 31, | | December 31, | | Increase | | Regulatory Assets By Source | | 2006 | | 2005 | | (Decrease) | | | | | (In millions) | | | Regulatory transition costs | | $ | 3,470 | | $ | 3,576 | | $ | (106 | ) | | Customer shopping incentives | | | 662 | | | 884 | | | (222 | ) | | Customer receivables for future income taxes | | | 215 | | | 217 | | | (2 | ) | | Societal benefits charge | | | 15 | | | 29 | | | (14 | ) | | Loss on reacquired debt | | | 40 | | | 41 | | | (1 | ) | | Employee postretirement benefits costs | | | 53 | | | 55 | | | (2 | ) | | Nuclear decommissioning, decontamination | | | | | | | | | | | and spent fuel disposal costs | | | (129 | ) | | (126 | ) | | (3 | ) | | Asset removal costs | | | (164 | ) | | (365 | ) | | 201 | | | Property losses and unrecovered plant costs | | | 27 | | | 29 | | | (2 | ) | | MISO transmission costs | | | 90 | | | 91 | | | (1 | ) | | RCP fuel recovery | | | 22 | | | - | | | 22 | | | RCP distribution costs | | | 40 | | | - | | | 40 | | | JCP&L reliability costs | | | 21 | | | 23 | | | (2 | ) | | Other | | | 34 | | | 32 | | | 2 | | | Total | | $ | 4,396 | | $ | 4,486 | | $ | (90 | ) |
Reliability Initiatives FirstEnergy is proceeding with the implementation of the recommendations that were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) in late 2003 and early 2004, regarding enhancements to regional reliability that were to be completed subsequent to 2004 and2004. FirstEnergy will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades to existing, equipment. FirstEnergy notes, however, thatThe FERC or other applicable government agencies and reliability coordinators, however, may take a different view as to recommended enhancements or may recommend additional enhancements in the future as the result of adoption of mandatory reliability standards pursuant to EPACT that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy'sour filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.
As a result of outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L's service reliability. On March 29,In 2004, the NJBPU adopted a Memorandum of Understanding (MOU)an MOU that set out specific tasks and a timetable for completion of actions related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L's ongoing actions to implement the MOU. On June 9, 2004, the NJBPUalso approved a Stipulation that incorporates the final report of an SRMa Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability and the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit). A Final Order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements.reliability. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.
In May 2004, the PPUC issued an order approving revised reliability benchmarks and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, due to their implementation of automated outage management systems following restructuring. On December 30, 2005, the ALJ recommended that the PPUC adopt the Joint Petition for Settlement among the parties involved in the three Companies’ request to amend the distribution reliability benchmarks, thereby eliminating the need for full litigation. The ALJ’s recommendation, adopting the revised benchmarks and standards, was approved by the PPUC on February 9, 2006.
EPACT provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC review. On February 3, 2006, the FERC adopted a rule establishing certification requirements for the ERO, as well as regional entities envisioned to assume monitoring responsibility for the new reliability standards. The FERC issued an order on rehearing on March 30, 2006, providing certain clarifications and essentially affirming the rule.
The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC’s certification requirements for the ERO. The NERC made a filing with the FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC approval of delegation agreements with regional entities. The new FERC rule referred to above, further provides for reorganizing regional reliability organizations (regional entities) that would replace the current regional councils and for rearranging the relationship with the ERO. The “regional entity” may be delegated authority by the ERO, subject to FERC approval, for enforcing reliability standards adopted by the ERO and approved by the FERC. NERC also made a parallel filing with the FERC April 4, 2006 seeking approval of mandatory reliability standards. These reliability standards are based with some modifications, on the current NERC Version O reliability standards with some additional standards. On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security standards and thirteen additional reliability standards. These standards will become effective on June 1, 2006 and will be filed with the FERC and relevant Canadian authorities for approval. The two filings are subject to review and acceptance by the FERC.
The ERO filing was noticed on April 7, 2006 and comments and interventions were filed on May 4, 2006. There is no fixed time for the FERC to act on this filing. The reliability standards filing was noticed by FERC on April 18, 2006. In that notice FERC announced its intent to treat the proposed reliability standards as a NOPR and issue a NOPR in July 2006. Prior to that time, the FERC staff will release a preliminary assessment of the proposed reliability standards. FERC also intends to hold a technical conference on the proposed reliability standards. A comment period will be set after the Staff assessment is released and the technical conference is held. NERC has requested an effective date of January 1, 2007 for the reliability standards.
The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils have completed the consolidation of these regions into a single new regional reliability organization known as ReliabilityFirst Corporation. ReliabilityFirst began operations as a regional reliability council under NERC on January 1, 2006 and intends to file and obtain certification consistent with the final rule as a “regional entity” under the ERO during 2006. All of FirstEnergy’s facilities are located within the ReliabilityFirst region.
FirstEnergy believes that it is in compliance with all current NERC reliability standards. However, it is expected that the FERC will adopt stricter reliability standards than those contained in the current NERC standards. The financial impact of complying with the new standards cannot be determined at this time. However, EPACT requires that all prudent costs incurred to comply with the new reliability standards be recovered in rates. If FirstEnergy is unable to meet the reliability standards for the bulk power system in the future, it could have a material adverse effect on the Company’s and its subsidiaries’ financial condition, results of operations and cash flows.
See Note 1311 to the consolidated financial statements for a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Met-Ed, Penelec and Penn.initiatives.
Ohio
On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The Ohio Companies' revised Rate Stabilization Plan extends currentRSP was intended to establish generation prices through 2008, ensuring adequate generationservice rates beginning January 1, 2006, in response to PUCO concerns about price and supply at stabilized prices, and continuesuncertainty following the end of the Ohio Companies' supporttransition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of energy efficiency and economic development efforts. Other key componentsOhio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming that order with respect to the approval of the revised Rate Stabilization Plan includerate stabilization charge, approval of the following:shopping credits, the grant of interest on shopping credit incentive deferral amounts, and approval of FirstEnergy’s financial separation plan. It remanded the approval of the RSP pricing back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient customer participation in the competitive marketplace.
· | extension of the amortization period for transition costs being recovered through the RTC for OE from 2006 to as late as 2007; for CEI from 2008 to as late as mid-2009 and for TE from mid-2007 to as late as mid-2008; |
· | deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and |
· | ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes. |
Under provisions of the RSP, the PUCO had required the Ohio Companies to undertake a CBP to secure generation and allow for customer pricing participation in the competitive marketplace. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until 12 months after the PUCO authorizes such termination. On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid processthe CBP for the generation supply period beginning January 1, 2006 and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan willRSP would take effect on January 1, 2006. On February 23, 2006 the CBP auction manager, National Economic Research Associates, notified the PUCO that a subsequent CBP to potentially provide firm generation service for the Ohio Companies' 2007 and 2008 actual load requirements could not proceed due to lack of interest, as there were no bidder applications submitted. Additionally, on March 20, 2006, the PUCO denied applications for rehearing filed by various parties regarding the PUCO's rules for the CBP. The PUCOabove May 3, 2006 Supreme Court of Ohio opinion may require the PUCO to reconsider this customer pricing process.
On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies' RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:
| · | Maintaining the existing level of base distribution rates through December 31, 2008 for OE and TE, and April 30, 2009 for CEI; |
| · | Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years; |
| · | Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for OE and TE and as of December 31, 2010 for CEI; |
| · | Reducing the deferred shopping incentive balances as of January 1, 2006 by up to $75 million for OE, $45 million for TE, and $85 million for CEI by accelerating the application of each respective company's accumulated cost of removal regulatory liability; and |
| · | Recovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all OE and TE distribution and transmission customers through a fuel recovery mechanism. OE, TE, and CEI may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the amount collected through the fuel recovery mechanism (in lieu of implementation of the GCAF rider). |
The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2006 through 2010:
Amortization | | | | | | | | Total | | Period | | OE | | CEI | | TE | | Ohio | | | | | (In millions) | | | 2006 | | $ | 172 | | $ | 97 | | $ | 83 | | $ | 352 | | | 2007 | | | 180 | | | 113 | | | 90 | | | 383 | | | 2008 | | | 206 | | | 130 | | | 108 | | | 444 | | | 2009 | | | - | | | 211 | | | - | | | 211 | | | 2010 | | | - | | | 263 | | | - | | | 263 | | Total Amortization | | $ | 558 | | $ | 814 | | $ | 281 | | $ | 1,653 | |
The PUCO’s January 4, 2006 approval of the RCP also included approval of the Ohio Companies’ supplemental stipulation which was filed with the PUCO on November 4, 2005 and which was an additional component of the RCP filed on September 9, 2005. On January 10, 2006, the Ohio Companies to undertake, no more often than annually,filed a similar competitive bid process to secure generationMotion for the years 2007 and 2008. Any acceptanceClarification of future competitive bid results would terminate the Rate Stabilization Plan pricing, but not the related approved accounting, and not until twelve months after the PUCO authorizes such termination.order approving the RCP. The Ohio Companies sought clarity on issues related to distribution deferrals, including requirements of the review process, timing for recognizing certain deferrals and definitions of the types of qualified expenditures. The Ohio Companies also sought confirmation that the list of deferrable distribution expenditures originally included in the revised stipulation fall within the PUCO order definition of qualified expenditures. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies’ requests to:
| · | Recognize fuel and distribution deferrals commencing January 1, 2006; | | | | | · | Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff; | | | |
| · | Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and | | | | | · | Clarify that distribution expenditures do not have to be “accelerated” in order to be deferred. | | | |
The PUCO approved the Ohio Companies’ methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies’ Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. The Ohio Companies responded to the applications for rehearing on February 13, 2006. In an Entry on Rehearing issued by the PUCO on March 1, 2006, all motions for rehearing were denied. Certain of these parties have subsequently filed their notices of appeal with the Supreme Court of Ohio alleging various errors made by the PUCO in its order approving the RCP.
On December 30, 2004, the Ohio Companies filed an application with the PUCO seeking tariff adjustmentstwo applications related to recover increasesthe recovery of approximately $30 million in transmission and ancillary service related costs. The first application sought recovery of these costs beginning January 1, 2006. The Ohio Companies alsorequested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues expected to be recovered from January through June 30, 2006 are approximately $66 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. On May 1, 2006, the Ohio Companies filed ana modification to the rider to determine revenues from July 2006 through June 2007.
The second application forsought authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees,transmission and ancillary service related costs incurred during the ATSI rate increase, as applicable,period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of the Ohio Companies' case with a similar case involving Dayton Power & Light Company. Oral arguments are currently scheduled for May 10, 2006.
On January 20, 2006 the OCC sought rehearing of the PUCO approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The OCC's brief is expected to be filed during the second quarter of 2006. The briefs of the PUCO and the Ohio Companies will be due within thirty days of the OCC's filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On April 18, 2006, the Court denied both parts of the motion but on its own motion consolidated the OCC's appeal of the Ohio Companies' case with a similar case of Dayton Power & Light Company and stayed briefing on these appeals.
See Note 1311 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.
New JerseyPennsylvania
As of March 31, 2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation are $328 million and $50 million, respectively. Penelec's $50 million is subject to the pending resolution of taxable income issues associated with NUG trust fund proceeds.
On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005. The July 2003 NJBPU decisionOCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. As of March 31, 2006, the PPUC had taken no action on JCP&L's base electric ratethe request and neither company had yet implemented deferral accounting for these costs. Met-Ed and Penelec sought to consolidate this proceeding ordered a Phase II proceeding be conducted(and modified their request to review whether JCP&L is in compliance with current service reliability and quality standards. The NJBPU also ordered that any expenditures and projects undertaken by JCP&L to increase its system's reliability be reviewed as partprovide deferral of the Phase II proceeding, to determine their prudence and reasonableness for rate recovery. 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. On July 16, 2004, JCP&L filed the Phase II petition and testimony2006 transmission-related costs only) with the NJBPU, requesting an increasecomprehensive rate filing they made on April 10, 2006 as described below. On May 4, 2006, the PPUC approved the modified request. Accordingly, Met-Ed and Penelec will implement deferral accounting for these costs in base ratesthe second quarter of $362006, which will include $24 million forand $4 million, respectively, representing the recoveryamounts that were incurred in the first quarter of system reliability costs and a 9.75% return on equity. The filing also requests an increase to2006 -- the MTC deferred balance recoverydeferrals of approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004, and JCP&L submitted rebuttal testimony on January 4, 2005. The Ratepayer Advocate surrebuttal testimony was submitted February 8, 2005. Discovery and settlement conferences are ongoing.such amounts will be reflected in the second quarter of 2006.
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 customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. 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. The Ratepayer Advocate filed comments on February 28, 2005. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further proceedings has not yet been set.
See Note 13 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.
Pennsylvania
Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales 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 wholesalethis 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 with NUGs and other power contracts with nonaffiliated third partyunaffiliated suppliers. ThisThe FES 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. The wholesale power sales agreement with FES could automatically be extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. On November 1, 2005, FES and the other parties thereto amended the agreement to provide FES the right in 2006 to terminate the agreement at any time upon 60 days notice. On April 7, 2006, the parties to the wholesale power sales agreement entered into a Tolling Agreement that arises out of FES’ notice to Met-Ed and Penelec are authorizedthat FES elected to continue deferring differences between NUG contract costs and current market prices.exercise its right to terminate the wholesale power sales agreement effective midnight December 31, 2006, because that agreement is not economically sustainable to FES.
OnIn lieu of allowing such termination to become effective as of December 31, 2006, the parties agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales agreement to provide as follows:
1.The termination provisions of the wholesale power sales agreement will be tolled for one year until December 31, 2007, provided that during such tolling period:
| a. | FES will be permitted to terminate the wholesale power sales agreement at any time with sixty days written notice; |
| b. | Met-Ed and Penelec will procure through arrangements other than the wholesale power sales agreement beginning December 1, 2006 and ending December 31, 2007, approximately 33% of the amounts of capacity and energy necessary to satisfy their PLR obligations for which Committed Resources (i.e., non-utility generation under contract to Met-Ed and Penelec, Met-Ed- and Penelec-owned generating facilities, purchased power contracts and distributed generation) have not been obtained; and |
| c. | FES will not be obligated to supply additional quantities of capacity and energy in the event that a supplier of Committed Resources defaults on its supply agreement. |
2.During the tolling period FES will not act as agent for Met-Ed or Penelec in procuring the services under section 1.(b) above; and
3.The pricing provision of the wholesale power sales agreement shall remain unchanged provided Met-Ed and Penelec comply with the provisions of the Tolling Agreement and any applicable provision of the wholesale power sales agreement.
In the event that FES elects not to terminate the wholesale power sales agreement effective midnight December 31, 2007, similar tolling agreements effective after December 31, 2007 are expected to be considered by FES for subsequent years if Met-Ed and Penelec procure through arrangements other than the wholesale power sales agreement approximately 64%, 83% and 95% of the additional amounts of capacity and energy necessary to satisfy their PLR obligations for 2008, 2009 and 2010, respectively, for which Committed Resources have not been obtained from the market.
The wholesale power sales agreement, as modified by the Tolling Agreement, requires Met-Ed and Penelec to satisfy the portion of their PLR obligations currently supplied by FES from unaffiliated suppliers at prevailing prices, which are likely to be higher than the current price charged by FES under the current agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. There can be no assurance, however, that if FES ultimately determines to terminate, or significantly modify the agreement, timely regulatory relief will be granted by the PPUC pursuant to the April 10, 2006 comprehensive rate filing discussed below, or, to the extent granted, adequate to mitigate such adverse consequences.
Met-Ed and Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 that addresses a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals is approved, the filing would increase annual revenues by $216 million and $157 million, respectively. That filing includes, among other things, a request to charge customers for an increasing amount of market priced power procured through a competitive bid process as the amount of supply provided under the existing FES agreement is phased out in accordance with the April 7, 2006 Tolling agreement described above. Met-Ed and Penelec also requested approval of the January 12, 2005 Met-Ed and Penelec filed, beforepetition for the PPUC, a request for deferral of transmission-related costs beginningdiscussed above, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2005, estimated2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider similar to that implemented in Ohio. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs are also included in the filing. The filing contemplates a reduction in distribution rates for Met-Ed in the amount of $37 million annually and an increase in distribution rates for Penelec in the amount of $20 million annually. Although the companies have proposed an effective date of June 10, 2006, it is expected that the PPUC will suspend the effective date for seven months as permitted under Pennsylvania law. Hearings are expected to be approximately $8 million per month.scheduled for the second half of 2006 and a PPUC decision is expected early in the first quarter of 2007. On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn recommended that the RFP process cover the period January 1, 2007 through May 31, 2008. Hearings were held on January 10, 2006 with main briefs filed on January 27, 2006 and reply briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a Recommended Decision to adopt Penn's RFP process with modifications. The PPUC approved the Recommended Decision with additional modifications on April 20, 2006. The approved plan is designed to provide customers with PLR service for January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.
See Note 1311 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania.
TransmissionNew Jersey
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 NUGC rates and market sales of NUG energy and capacity. As of March 31, 2006, the accumulated deferred cost balance totaled approximately $558 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval to securitize the July 31, 2003 deferred balance. On December 2, 2005, JCP&L filed a request for recovery of $165 million of actual above-market NUG costs incurred from August 1, 2003 through October 31, 2005 and forecasted above-market NUG costs for November and December 2005. On February 1, 2006, the NJBPU selected Bear Stearns as the financial advisor. Meetings with the NJBPU Staff and the DRA were held during March and April and additional discovery conducted. The DRA filed comments on April 6, 2006, arguing that the proposed securitization does not produce customer savings. JCP&L submitted reply comments on April 10, 2006. On February 23, 2006, JCP&L filed updated data reflecting actual amounts through December 31, 2005 of $154 million of cost incurred since July 31, 2003. The filing also includes a request for recovery of $49 million for above-market NUG costs incurred prior to August 1, 2003, to the extent those costs are not recoverable through securitization. On March 29, 2006, a pre-hearing conference was held with the presiding ALJ. A schedule for the proceeding was established including a discovery period and evidentiary hearings scheduled for September 2006.
An NJBPU Decision and Order approving a Phase II Stipulation of Settlement and resolving the Motion for Reconsideration of the Phase I Order was issued on May 31, 2005. The Phase II Settlement includes a performance standard pilot program with potential penalties of up to 0.25% of equity return. The Order requires that JCP&L file quarterly reliability reports (CAIDI and SAIFI information related to the performance pilot program) through December 2006 and updates to reliability related project expenditures until all projects are completed. The first quarterly report was submitted to NJBPU on August 16, 2005. The second quarterly report was submitted on November 22, 2005. The third quarterly report as of December 31, 2005 was submitted on March 28, 2006. As of December 31, 2005 there were no performance penalties issued by the NJBPU.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the recent repeal of PUHCA under the EPACT. An NJBPU proposed rulemaking to address the issues was published in the NJ Register on December 19, 2005. The proposal would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. A public hearing was held February 7, 2006 and comments were submitted to the NJBPU. The NJBPU Staff issued a draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. Comments and reply comments are due by May 22 and May 31, 2006, respectively. JCP&L is not able to predict the outcome of this proceeding at this time.
See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.
FERC Matters On September 16,November 18, 2004, the FERC issued an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEIeliminating the regional through and the cities of Cleveland and Painesville, Ohio. Under the FERC's decision, CEI may be responsible for a portion of new energy market charges imposed by 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. On April 15, 2005, the FERC issued an order on rehearing that "carves out" these contracts from the MISO Day 2 market. While the order on rehearing is favorable to CEI, the impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the citiesout rates (RTOR) for transmission service between the MISO and MISO's abilityPJM regions. The FERC also ordered the MISO, PJM and the transmission owners within the MISO and PJM to administersubmit compliance filings containing a mechanism - the contracts. Accordingly,Seams Elimination Cost Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the impactSECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be involved in the FERC hearings concerning the calculation and imposition of thisthe SECA charges. The hearing began on May 1, 2006. The FERC has ordered the Presiding Judge to issue an initial decision cannot be determined at this time.by August 11, 2006.
On November 1, 2004, ATSI requested authority from thefiled with FERC a request to defer approximately $54 million of vegetation management costs ($14 million deferred as of March 31, 2005) estimated to be incurred from 2004 through 2007.2007 in connection with ATSI’s Vegetation Management Enhancement Project (VMEP), which represents ATSI’s adoption of newly identified industry “best practices” for vegetation management. On March 4, 2005, the FERC approved ATSI'sATSI’s request to defer those costs. ATSI expects to file an application with FERC in the first quarterVMEP costs (approximately $29 million deferred as of March 31, 2006). On March 28, 2006 for recovery of the deferred costs.
ATSI and MISO filed with FERC a request to modify ATSI’s Attachment O formula rate to include revenue requirements associated with recovery of deferred VMEP costs over a five-year period. The requested effective date to begin recovery is June 1, 2006. Various parties have filed comments responsive to the March 28, 2006 submission. The FERC has not taken any action on the filing. The estimated impact of the VMEP cost recovery is $13 million in revenues annually during the five-year recovery period of June 1, 2006 to May 31, 2011.
On January 24, 2006, ATSI and MISO filed with FERC a request to correct ATSI’s Attachment O formula rate to reverse revenue credits associated with termination of revenue streams from transitional rates stemming from FERC’s elimination of through and out rates. Revenues formerly collected under these rates were included in, and served to reduce, ATSI’s zonal transmission rate under the Attachment O formula. Absent the requested correction, elimination of these revenue streams would not be fully reflected in ATSI’s formula rate until June 1, 2008. On March 16, 2006, FERC approved without suspension the revenue credit correction, which became effective April 1, 2006. One party sought rehearing of the FERC order. The FERC has not yet issued a further order. The estimated impact of the correction mechanism is approximately $40 million in revenues on December 2, 2004, seeking approval for ATSIan annualized basis beginning June 1, 2006.
On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to havea settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission rates established basedowners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a FERC-approved cost of service - formula rate includedfor transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in Attachment O underopposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. Second, the MISO tariff. The ATSI Network Service net revenue requirement increased underFERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order. On March 20, 2006 a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued an order approving this settlement on April 19, 2006. If the FERC accepts AEP's proposal, significant additional transmission revenues would be imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within PJM.
On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to approximately $159 million. provide the PLR requirements of the Ohio Companies at a price equal to the retail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio competitive bid process results in a lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. The PPUC approved Penn's plan with modifications on April 20, 2006 to use an RFP process to obtain its power supply requirements after 2006.
On January 28,December 29, 2005, the FERC acceptedissued an order setting the two power sales agreements for filinghearing. The order criticized the revised tariff sheetsOhio competitive bid process, and required FES to become effective February 1, 2005, subject to refund, and ordered a public hearing be held to addresssubmit additional evidence in support of the reasonableness of the proposalprices charged in the power sales agreements. A pre-hearing conference was held on January 18, 2006 to eliminatedetermine the voltage-differentiated rate design forhearing schedule in this case. FES expects an initial decision to be issued in this case in late January 2007, as a result of an April 20, 2006 extension of the ATSI zone. On April 4,procedural schedule. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 a settlement with all parties to the proceeding was filed withorder and the FERC that providesgranted rehearing for recovery of the full amount of the rate increase permitted under the formula.further consideration on March 1, 2006.
Environmental Matters
The Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably determineestimate the amount of such costs. Unasserted claims are reflected in the Companies’Companies' determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
On December 1, 2005, FirstEnergy issued a comprehensive report to shareholders regarding air emissions regulations and an assessment of future risks and mitigation efforts. The report is available on FirstEnergy's web site at www.firstenergycorp.com/environmental.
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 March 10, 2005, the EPA finalized the "Clean Air Interstate Rule"CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainmentnon-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR will requireprovides each affected state until 2006 to develop implementing regulations to achieve additional reductions of NOxX and SO2 emissions in two phases (Phase I in 2009 for NOxX, 2010 for SO2 and Phase II in 2015 for both NOxX and SO2). The Companies’FirstEnergy's Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO2and NOxX emissions, whereas ourits New Jersey fossil-fired generation facilities will be subject to a cap on NOxX emissions only. According to the EPA, SO2emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOxX emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOxX cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on 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 March 14, 2005, the EPA finalized CAMR, which provides for a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants.plants in two phases. Initially, mercury emissions will declinebe capped nationally at 38 tons by 2010 as(as a "co-benefit" from implementation of SO2 and NOxX emission caps under the EPA's CAIR program.program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. TheHowever, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both CAIR and CAMR have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial.substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.
The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FirstEnergy would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced. Since this approach is based on output, new and non-emitting generating facilities, including renewables and nuclear, would be entitled to their proportionate share of the allowances. Consequently, FirstEnergy would be disadvantaged if these model rules were implemented because FirstEnergy's substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.
W. H. Sammis Plant
In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities coveringalleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which iswas owned at that time by OE and Penn. In addition, the U.S. Department of Justice (DOJ)DOJ filed eight civil complaints against various investor-owned utilities, which includedincluding 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. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement which is inwas approved by the form of a Consent Decree subject to a thirty-day public comment period that endedCourt on April 29,July 11, 2005, and final approval by the District Court Judge, requires OEreductions of NOX and Penn to reduceSO2 emissions fromat the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices requiring capitaland provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the settlement agreement. Capital expenditures necessary to meet those requirements are currently estimated to be $1.1$1.5 billion (primarily(the primary portion of which is expected to be spent in the 2008 to 2011 time period). On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million towardstoward environmentally beneficial projects, which include wind energy purchasepurchased power agreements over a 20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 includeincluded the penalties payablepaid by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also accruedrecognized liabilities in the first quarter of 2005 of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects during the first quarter of 2005.projects.
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 gasesGHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gasGHG intensity - the ratio of emissions to economic output - by 18 percent18% through 2012. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.
The CompaniesFirstEnergy 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 include low or non-CO2 emitting gas-fired and nuclear generators.
FirstEnergy plans to issue a report that will disclose the Companies’ environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by December 1, 2005 and will post the report on its web site,www.firstenergycorp.com.
Regulation of Hazardous 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 March 31, 2005,2006, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliatedunaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; thoseJersey. Those costs are being recovered by JCP&L through a non-bypassable SBC. Included in Current Liabilities and Other Noncurrent Liabilities areTotal liabilities of approximately $63 million have been accrued liabilities aggregating approximately $65 million as ofthrough March 31, 2005.2006.
See Note 12(B)10(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.
Other Legal Proceedings
There are various lawsuits, claims (including claims for asbestos exposure)Power Outages and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The most significant not otherwise discussed above are described below.Related Litigation
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. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,concluded, 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 real-time 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 contained 46 "recommendations“recommendations to prevent or minimize the scope of future blackouts."” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in process,new or material upgrades to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother applicable government agencies and reliability coordinators may, however, 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 asFinally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of March 31, 2005 forcontrol room operators before determining the next steps, if any, expenditures in excess of those actually incurred through that date.
One complaint was filed on August 25, 2004 against FirstEnergy in the New Yorkproceeding.
FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in Ohio State Supreme Court.courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In thisthese cases the individual complainants—three in one case several plaintiffsand four in the New York City metropolitan area allegeother—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that they sufferedits rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of the four cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc. as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. On March 7, 2006, the PUCO issued a ruling applicable to all pending cases. Among its various rulings, the PUCO consolidated all of the pending outage cases for hearing; limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence; and gave the plaintiffs additional time to amend their complaints to otherwise comply with the PUCO’s underlying order. The plaintiffs in one case have since filed an amended complaint. The named FirstEnergy companies have answered and also have filed a motion to dismiss the action, which is pending. Also, most complainants, along with the FirstEnergy companies, filed applications for rehearing with the PUCO over various rulings contained in the March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow the insurance company claimants, as insurers, to prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities which provide their service. The PUCO denied all other motions for rehearing. No estimate of potential liability is available for any of these cases. In addition to these six cases, 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. None ofFollowing the plaintiffs are customersPUCO's March 7, 2006 order, that action was voluntarily dismissed by the claimants.
In addition to the above proceedings, FirstEnergy was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy affiliate.company. A responsive pleading to this matter has been filed. FirstEnergy filedwas also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy are based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. No FirstEnergy entity serves any customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss withdismiss. It is uncertain whether the Court on October 22, 2004.plaintiff will appeal. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thusof potential liability has not been determined.undertaken in either of these matters.
FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular,Although unable to predict the impact of these proceedings, 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.operations and cash flows.
On January 20, 2006, FENOC receivedannounced that it has entered into a subpoena in late 2003 from a grand jury sitting indeferred prosecution agreement with the United States District CourtU.S. Attorney’s Office for the Northern District of Ohio Eastern Division requestingand the production of certain documents and records relating to the inspection and maintenanceEnvironmental Crimes Section of the Environment and Natural Resources Division of the DOJ related to FENOC’s communications with the NRC during the fall of 2001 in connection with the reactor vessel head issue at the Davis-Besse Nuclear Power Station. OnUnder the agreement, which expires on December 10, 2004, FirstEnergy received a letter from31, 2006, the United States Attorney's Office stating thatacknowledged FENOC’s extensive corrective actions at Davis-Besse, FENOC’s cooperation during investigations by the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related criminal and administrative investigations and proceedings, FENOC’s acknowledgement of responsibility for the behavior of its employees, and its agreement to pay a monetary penalty. The DOJ will refrain from seeking an indictment or otherwise initiating criminal prosecution of FENOC is a target of the federal grand jury investigation into alleged false statements madefor all conduct related to the NRCstatement of facts attached to the deferred prosecution agreement, as long as FENOC remains in compliance with the agreement, which FENOC fully intends to do. FENOC paid a monetary penalty of $28 million (which is not deductible for income tax purposes) which reduced First Energy's earnings by $0.09 per common share in the Fallfourth quarter of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse.2005. On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head describedissue discussed above. Under the NRC’s letter, FENOC has ninety daysFirstEnergy accrued $2 million for a potential fine prior to respond to this NOV. FirstEnergy has2005 and accrued the remaining liability for the proposed fine of $3.45 million during the first quarter of 2005. If it were ultimately determined On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy orpaid the penalty in the third quarter of 2005. On January 23, 2006, FENOC supplemented its subsidiaries has legal liability basedresponse to the NRC's NOV on the Davis-Besse head degradation it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.to reflect the deferred prosecution agreement that FENOC had reached with the DOJ.
On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the pastpreceding two years.years and the licensee's failure to take prompt and corrective action. FENOC operates the Perry Nuclear Power Plant, which is owned and/or leased by OE, CEI, TE and Penn.OnPlant.
On April 4, 2005, the NRC held a public forummeeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives althougheven though it remained under the heightened NRC oversight since August 2004.oversight. During the public forummeeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. By an inspection report dated January 18, 2006, the NRC closed one of the White Findings (related to emergency preparedness) which led to the multiple degraded cornerstones.
On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's 2005 annual assessment letter dated March 2, 2006 and associated meetings to discuss the performance of Perry on March 14, 2006, the NRC again stated that the Perry Plant continued to operate in a manner that "preserved public health and safety." However, the NRC also stated that increased levels of regulatory oversight would continue until sustained improvement in the performance of the facility was realized. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these mattersAlthough FirstEnergy is unable to predict the impact of the ultimate disposition of this matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.condition, results of operations and cash flows.
As of December 16, 2005, NGC acquired ownership of the nuclear generation assets transferred from OE, CEI, TE and Penn with the exception of leasehold interests of OE and TE in certain of the nuclear plants that are subject to sale and leaseback arrangements with non-affiliates.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other material items 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, have 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. On December 30, 2004, FirstEnergy received a second subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse related disclosures, which FirstEnergy has provided. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.
On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.
JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, the federal court granted a Union motion to dismiss JCP&L's appeal of the award as premature. JCP&L will file its appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.
The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will decide this case.
If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy'sFirstEnergy’s or its subsidiaries'subsidiaries’ financial condition, and results of operations.operations and cash flows.
See Note 12(C)10(C) to the consolidated financial statements for further details and a complete discussion of these and other legal proceedings.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
FIN 47,“AccountingEITF Issue 04-13, "Accounting for Conditional Asset Retirement Obligations -Purchases and Sales of Inventory with the Same Counterparty"
In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an interpretationexchange of FASB Statement No. 143”inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, FirstEnergy will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. This EITF issue will not have a material impact on FirstEnergy's financial results.
On March 30, 2005,SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140”
In February 2006, the FASB issued this interpretation to clarify the scopeSFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and timingHedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for theFinancial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an asset retirement obligationembedded derivative requiring bifurcation, clarifies that is conditionalconcentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient informationqualifying special-purpose entity from holding a derivative financial instrument that pertains to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed.a beneficial interest other than another derivative instrument. This interpretationStatement is effective no later than the end of fiscal years ending after December 15, 2005.for all financial instruments acquired or issued beginning January 1, 2007. FirstEnergy is currently evaluating the effectimpact of this standard will haveStatement on theits financial statements.
SFAS 123 (revised 2004),“Share-Based Payment”
In December 2004, the FASB issued this revision to SFAS 123, which requires expensing stock options in the financial statements. Important to applying the new standard is understanding how to (1) measure the fair value of stock-based compensation awards and (2) recognize the related compensation cost for those awards. For an award to qualify for equity classification, it must meet certain criteria in SFAS 123(R). An award that does not meet those criteria will be classified as a liability and remeasured each period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensation. In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule results in a six-month deferral for FirstEnergy and other companies with a fiscal year beginning January 1. The Company will be applying modified prospective application, without restatement of prior interim periods. Any potential cumulative adjustments have not been determined. FirstEnergy uses the Black-Scholes option-pricing model to value options and will continue to do so upon adoption of SFAS 123(R).
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
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.
OHIO EDISON COMPANY | OHIO EDISON COMPANY | | OHIO EDISON COMPANY | | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | (Unaudited) | | (Unaudited) | | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | | March 31, | | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | 2005 | | 2004 | | | March 31, | | | | | | | | | | | | 2006 | | 2005 | | STATEMENTS OF INCOME | | | | (In thousands) | | | (In thousands) | | | | | | | | | | | | | | | | OPERATING REVENUES | | | | | $ | 726,358 | | $ | 743,295 | | | $ | 586,203 | | $ | 726,358 | | | | | | �� | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | | | Fuel | | | | | 11,916 | | 15,070 | | | | 2,951 | | | 11,916 | | | Purchased power | | | | | 246,590 | | 249,881 | | | | 272,386 | | | 246,590 | | | Nuclear operating costs | | | | | 95,653 | | 79,641 | | | | 41,084 | | | 95,653 | | | Other operating costs | | | | | 83,179 | | 85,360 | | | | 90,810 | | | 83,179 | | | Provision for depreciation | | | | | 26,052 | | 29,929 | | | | 18,016 | | | 26,052 | | | Amortization of regulatory assets | | | | | 111,771 | | 113,695 | | | | 53,861 | | | 111,771 | | | Deferral of new regulatory assets | | | | | (24,795 | ) | | (18,895 | ) | | | (25,606 | ) | | (24,795 | ) | | General taxes | | | | | 48,078 | | 48,566 | | | | 45,895 | | | 48,078 | | | Income taxes | | | | | | 54,972 | | | 61,574 | | | | 30,550 | | | 54,972 | | | Total operating expenses and taxes | | | | | | 653,416 | | | 664,821 | | | | 529,947 | | | 653,416 | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | | | 72,942 | | 78,474 | | | | 56,256 | | | 72,942 | | | | | | | | | | | | | | | | | | | OTHER INCOME (net of income taxes) | | | | | 423 | | 16,357 | | | | 25,470 | | | 423 | | | | | | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | | | | | | Interest on long-term debt | | | | | 15,609 | | 16,589 | | | | 13,082 | | | 15,609 | | | Allowance for borrowed funds used during construction and capitalized interest | | | | | (2,235 | ) | | (1,381 | ) | | | (491 | ) | | (2,235 | ) | | Other interest expense | | | | | 2,594 | | 2,890 | | | | 5,149 | | | 2,594 | | | Subsidiary's preferred stock dividend requirements | | | | | | 640 | | | 640 | | | | 156 | | | 640 | | | Net interest charges | | | | | 16,608 | | 18,738 | | | | 17,896 | | | 16,608 | | | | | | | | | | | | | | | | | | | NET INCOME | | | | | 56,757 | | 76,093 | | | | 63,830 | | | 56,757 | | | | | | | | | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | | | | 659 | | | 561 | | | | 659 | | | 659 | | | | | | | | | | | | | | | | | | | EARNINGS ON COMMON STOCK | | | | | $ | 56,098 | | $ | 75,532 | | | $ | 63,171 | | $ | 56,098 | | | | | | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | | | | $ | 56,757 | | $ | 76,093 | | | $ | 63,830 | | $ | 56,757 | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | Unrealized gain (loss) on available for sale securities | | | | | (2,717 | ) | | 5,167 | | | | 5,735 | | | (2,717 | ) | | Income tax related to other comprehensive income | | | | | | 1,124 | | | (2,131 | ) | | | Income tax expense (benefit) related to other comprehensive income | | | | 2,069 | | | (1,124 | ) | | Other comprehensive income (loss), net of tax | | | | | | (1,593 | ) | | 3,036 | | | | 3,666 | | | (1,593 | ) | | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | | | | $ | 55,164 | | $ | 79,129 | | | $ | 67,496 | | $ | 55,164 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral partof these statements. | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part | | The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part | | | | of these statements. | | | | | | | | |
OHIO EDISON COMPANY | | | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | | | March 31, | | December 31, | | | | | | | 2005 | | 2004 | | | | | | | (In thousands) | | ASSETS | | | | | | | | | UTILITY PLANT: | | | | | | | | | In service | | | | | $ | 5,470,159 | | $ | 5,440,374 | | | Less - Accumulated provision for depreciation | | | | | | 2,747,377 | | | 2,716,851 | | | | | | | | | 2,722,782 | | | 2,723,523 | | | Construction work in progress- | | | | | | | | | | | | Electric plant | | | | | | 233,967 | | | 203,167 | | | Nuclear fuel | | | | | | 39,468 | | | 21,694 | | | | | | | | | 273,435 | | | 224,861 | | | | | | | | | 2,996,217 | | | 2,948,384 | | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | Investment in lease obligation bonds | | | | | | 354,457 | | | 354,707 | | | Nuclear plant decommissioning trusts | | | | | | 445,704 | | | 436,134 | | | Long-term notes receivable from associated companies | | | | | | 208,364 | | | 208,170 | | | Other | | | | | | 42,720 | | | 48,579 | | | | | | | | | 1,051,245 | | | 1,047,590 | | | CURRENT ASSETS: | | | | | | | | | | | | Cash and cash equivalents | | | | | | 1,204 | | | 1,230 | | | Receivables- | | | | | | | | | | | | Customers (less accumulated provisions of $6,179,000 and $6,302,000, respectively, | | | | | | | | | | | | for uncollectible accounts) | | | | | | 267,911 | | | 274,304 | | | Associated companies | | | | | | 163,201 | | | 245,148 | | | Other (less accumulated provisions of $82,000 and $64,000, respectively, | | | | | | | | | | | | for uncollectible accounts) | | | | | | 20,602 | | | 18,385 | | | Notes receivable from associated companies | | | | | | 692,715 | | | 538,871 | | | Materials and supplies, at average cost | | | | | | 105,906 | | | 90,072 | | | Prepayments and other | | | | | | 25,981 | | | 13,104 | | | | | | | | | 1,277,520 | | | 1,181,114 | | | DEFERRED CHARGES: | | | | | | | | | | | | Regulatory assets | | | | | | 1,022,241 | | | 1,115,627 | | | Property taxes | | | | | | 61,419 | | | 61,419 | | | Unamortized sale and leaseback costs | | | | | | 58,896 | | | 60,242 | | | Other | | | | | | 71,327 | | | 68,275 | | | | | | | | | 1,213,883 | | | 1,305,563 | | | | | | | | $ | 6,538,865 | | $ | 6,482,651 | | | CAPITALIZATION AND LIABILITIES | | | | | | | | | | | | CAPITALIZATION: | | | | | | | | | | | | Common stockholder's equity- | | | | | | | | | | | | Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding | | | | | $ | 2,098,729 | | $ | 2,098,729 | | | Accumulated other comprehensive loss | | | | | | (48,711 | ) | | (47,118 | ) | | Retained earnings | | | | | | 451,296 | | | 442,198 | | | Total common stockholder's equity | | | | | | 2,501,314 | | | 2,493,809 | | | Preferred stock | | | | | | 60,965 | | | 60,965 | | | Preferred stock of consolidated subsidiary | | | | | | 39,105 | | | 39,105 | | | Long-term debt and other long-term obligations | | | | | | 1,098,801 | | | 1,114,914 | | | | | | | | | 3,700,185 | | | 3,708,793 | | | CURRENT LIABILITIES: | | | | | | | | | | | | Currently payable long-term debt | | | | | | 397,256 | | | 398,263 | | | Short-term borrowings- | | | | | | | | | | | | Associated companies | | | | | | 75,969 | | | 11,852 | | | Other | | | | | | 134,072 | | | 167,007 | | | Accounts payable- | | | | | | | | | | | | Associated companies | | | | | | 151,151 | | | 187,921 | | | Other | | | | | | 7,498 | | | 10,582 | | | Accrued taxes | | | | | | 197,848 | | | 153,400 | | | Other | | | | | | 126,265 | | | 74,663 | | | | | | | | | 1,090,059 | | | 1,003,688 | | | NONCURRENT LIABILITIES: | | | | | | | | | | | | Accumulated deferred income taxes | | | | | | 726,080 | | | 766,276 | | | Accumulated deferred investment tax credits | | | | | | 59,135 | | | 62,471 | | | Asset retirement obligation | | | | | | 344,715 | | | 339,134 | | | Retirement benefits | | | | | | 309,915 | | | 307,880 | | | Other | | | | | | 308,776 | | | 294,409 | | | | | | | | | 1,748,621 | | | 1,770,170 | | | COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | | | | | | | | $ | 6,538,865 | | $ | 6,482,651 | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets. | | | |
OHIO EDISON COMPANY | | | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | March 31, | | | | December 31, | | | | | 2006 | | | | 2005 | | | | | (In thousands) | | ASSETS | | | | | | | | UTILITY PLANT: | | | | | | | | | In service | | $ | 2,552,488 | | | | | $ | 2,526,851 | | | Less - Accumulated provision for depreciation | | | 996,292 | | | | | | 984,463 | | | | | | 1,556,196 | | | | | | 1,542,388 | | | Construction work in progress | | | 56,728 | | | | | | 58,785 | | | | | | 1,612,924 | | | | | | 1,601,173 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | Investment in lease obligation bonds | | | 325,519 | | | | | | 325,729 | | | Nuclear plant decommissioning trusts | | | 109,497 | | | | | | 103,854 | | | Long-term notes receivable from associated companies | | | 1,758,377 | | | | | | 1,758,776 | | | Other | | | 43,491 | | | | | | 44,210 | | | | | | 2,236,884 | | | | | | 2,232,569 | | CURRENT ASSETS: | | | | | | | | | | | | Cash and cash equivalents | | | 1,048 | | | | | | 929 | | | Receivables- | | | | | | | | | | | | Customers (less accumulated provisions of $8,136,000 and $7,619,000, respectively, | | | | | | | | | | | | for uncollectible accounts) | | | 251,937 | | | | | | 290,887 | | | Associated companies | | | 104,839 | | | | | | 187,072 | | | Other (less accumulated provisions of $23,000 and $4,000, respectively, | | | | | | | | | | | | for uncollectible accounts) | | | 20,239 | | | | | | 15,327 | | | Notes receivable from associated companies | | | 582,252 | | | | | | 536,629 | | | Prepayments and other | | | 27,017 | | | | | | 93,129 | | | | | | 987,332 | | | | | | 1,123,973 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | Regulatory assets | | | 757,164 | | | | | | 774,983 | | | Prepaid pension costs | | | 226,314 | | | | | | 224,813 | | | Property taxes | | | 52,897 | | | | | | 52,875 | | | Unamortized sale and leaseback costs | | | 53,888 | | | | | | 55,139 | | | Other | | | 29,013 | | | | | | 31,752 | | | | | | 1,119,276 | | | | | | 1,139,562 | | | | | $ | 5,956,416 | | | | | $ | 6,097,277 | | CAPITALIZATION AND LIABILITIES | | | | | | | | | | | CAPITALIZATION: | | | | | | | | | | | | Common stockholder's equity- | | | | | | | | | | | | Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding | | $ | 2,297,289 | | | | | $ | 2,297,253 | | | Accumulated other comprehensive income | | | 7,760 | | | | | | 4,094 | | | Retained earnings | | | 229,015 | | | | | | 200,844 | | | Total common stockholder's equity | | | 2,534,064 | | | | | | 2,502,191 | | | Preferred stock not subject to mandatory redemption | | | 60,965 | | | | | | 60,965 | | | Preferred stock of consolidated subsidiary not subject to mandatory redemption | | | 14,105 | | | | | | 14,105 | | | Long-term debt and other long-term obligations | | | 931,507 | | | | | | 1,019,642 | | | | | | 3,540,641 | | | | | | 3,596,903 | | CURRENT LIABILITIES: | | | | | | | | | | | | Currently payable long-term debt | | | 309,445 | | | | | | 280,255 | | | Short-term borrowings- | | | | | | | | | | | | Associated companies | | | - | | | | | | 57,715 | | | Other | | | 22,584 | | | | | | 143,585 | | | Accounts payable- | | | | | | | | | | | | Associated companies | | | 181,663 | | | | | | 172,511 | | | Other | | | 10,123 | | | | | | 9,607 | | | Accrued taxes | | | 191,375 | | | | | | 163,870 | | | Accrued interest | | | 12,054 | | | | | | 8,333 | | | Other | | | 95,273 | | | | | | 61,726 | | | | | | 822,517 | | | | | | 897,602 | | NONCURRENT LIABILITIES: | | | | | | | | | | | | Accumulated deferred income taxes | | | 764,337 | | | | | | 769,031 | | | Accumulated deferred investment tax credits | | | 23,194 | | | | | | 24,081 | | | Asset retirement obligation | | | 84,282 | | | | | | 82,527 | | | Retirement benefits | | | 292,965 | | | | | | 291,051 | | | Deferred revenues - electric service programs | | | 113,930 | | | | | | 121,693 | | | Other | | | 314,550 | | | | | | 314,389 | | | | | | 1,593,258 | | | | | | 1,602,772 | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | | | | $ | 5,956,416 | | | | | $ | 6,097,277 | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets. | | | | | | | | | | | | | |
OHIO EDISON COMPANY | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | March 31, | | | | | | | | | | | | | | | | 2005 | | 2004 | | | | | | | | | | | | | | | | (In thousands) | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | Net income | | | | | $ | 56,757 | | $ | 76,093 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | | | Provision for depreciation | | | | | | 26,052 | | | 29,929 | | | Amortization of regulatory assets | | | | | | 111,771 | | | 113,695 | | | Deferral of new regulatory assets | | | | | | (24,795 | ) | | (18,895 | ) | | Nuclear fuel and lease amortization | | | | | | 9,170 | | | 11,261 | | | Amortization of lease costs | | | | | | 33,030 | | | 33,030 | | | Deferred income taxes and investment tax credits, net | | | | | | (24,627 | ) | | (30,045 | ) | | Accrued retirement benefit obligations | | | | | | 2,034 | | | 11,123 | | | Accrued compensation, net | | | | | | (4,007 | ) | | 4,522 | | | Decrease (Increase) in operating assets: | | | | | | | | | | | | Receivables | | | | | | 86,123 | | | (51,935 | ) | | Materials and supplies | | | | | | (15,834 | ) | | (2,762 | ) | | Prepayments and other current assets | | | | | | (12,877 | ) | | (11,829 | ) | | Increase (Decrease) in operating liabilities: | | | | | | | | | | | | Accounts payable | | | | | | (39,854 | ) | | 240,979 | | | Accrued taxes | | | | | | 44,448 | | | (311,577 | ) | | Accrued interest | | | | | | 6,993 | | | 5,443 | | | Other | | | | | | 11,714 | | | 5,991 | | | Net cash provided from operating activities | | | | | | 266,098 | | | 105,023 | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | New Financing- | | | | | | | | | | | | Long-term debt | | | | | | -- | | | 30,000 | | | Short-term borrowings, net | | | | | | 31,182 | | | 16,341 | | | Redemptions and Repayments- | | | | | | | | | | | | Long-term debt | | | | | | (15,787 | ) | | (97,001 | ) | | Dividend Payments- | | | | | | | | | | | | Common stock | | | | | | (47,000 | ) | | (54,000 | ) | | Preferred stock | | | | | | (659 | ) | | (561 | ) | | Net cash used for financing activities | | | | | | (32,264 | ) | | (105,221 | ) | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | Property additions | | | | | | (79,783 | ) | | (37,661 | ) | | Contributions to nuclear decommissioning trusts | | | | | | (7,885 | ) | | (7,885 | ) | | Loan repayments from (loans to) associated companies, net | | | | | | (154,038 | ) | | 48,912 | | | Other | | | | | | 7,846 | | | (3,728 | ) | | Net cash used for investing activities | | | | | | (233,860 | ) | | (362 | ) | | | | | | | | | | | | | | Net decrease in cash and cash equivalents | | | | | | (26 | ) | | (560 | ) | | Cash and cash equivalents at beginning of period | | | | | | 1,230 | | | 1,883 | | | Cash and cash equivalents at end of period | | | | | $ | 1,204 | | $ | 1,323 | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral partof these statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
OHIO EDISON COMPANY | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | Three Months Ended | | | | | March 31, | | | | | | | | | | | | | | 2006 | | | | 2005 | | | | | (In thousands) | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | Net income | | $ | 63,830 | | | | | $ | 56,757 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | | | Provision for depreciation | | | 18,016 | | | | | | 26,052 | | | Amortization of regulatory assets | | | 53,861 | | | | | | 111,771 | | | Deferral of new regulatory assets | | | (25,606 | ) | | | | | (24,795 | ) | | Nuclear fuel and lease amortization | | | 532 | | | | | | 9,170 | | | Deferred purchased power costs | | | (10,634 | ) | | | | | - | | | Amortization of lease costs | | | 32,934 | | | | | | 33,030 | | | Deferred income taxes and investment tax credits, net | | | (3,945 | ) | | | | | (24,627 | ) | | Accrued compensation and retirement benefits | | | (1,494 | ) | | | | | (1,973 | ) | | Decrease (increase) in operating assets- | | | | | | | | | | | | Receivables | | | 116,271 | | | | | | 86,123 | | | Materials and supplies | | | - | | | | | | (15,834 | ) | | Prepayments and other current assets | | | 66,112 | | | | | | (12,877 | ) | | Increase (decrease) in operating liabilities- | | | | | | | | | | | | Accounts payable | | | 9,668 | | | | | | (39,854 | ) | | Accrued taxes | | | 27,505 | | | | | | 44,448 | | | Accrued interest | | | 3,721 | | | | | | 6,993 | | | Electric service prepayment programs | | | (7,763 | ) | | | | | - | | | Other | | | 3,922 | | | | | | 13,297 | | | Net cash provided from operating activities | | | 346,930 | | | | | | 267,681 | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | New Financing- | | | | | | | | | | | | Short-term borrowings, net | | | - | | | | | | 31,182 | | | Redemptions and Repayments- | | | | | | | | | | | | Long-term debt | | | (59,506 | ) | | | | | (15,787 | ) | | Short-term borrowings, net | | | (178,716 | ) | | | | | - | | | Dividend Payments- | | | | | | | | | | | | Common stock | | | (35,000 | ) | | | | | (47,000 | ) | | Preferred stock | | | (659 | ) | | | | | (659 | ) | | Net cash used for financing activities | | | (273,881 | ) | | | | | (32,264 | ) | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | Property additions | | | (28,793 | ) | | | | | (79,783 | ) | | Proceeds from nuclear decommissioning trust fund sales | | | 19,054 | | | | | | 68,400 | | | Investments in nuclear decommissioning trust funds | | | (19,054 | ) | | | | | (76,285 | ) | | Loans to associated companies, net | | | (45,224 | ) | | | | | (154,038 | ) | | Other | | | 1,087 | | | | | | 6,263 | | | Net cash used for investing activities | | | (72,930 | ) | | | | | (235,443 | ) | | | | | | | | | | | | | | Net increase (decrease) in cash and cash equivalents | | | 119 | | | | | | (26 | ) | | Cash and cash equivalents at beginning of period | | | 929 | | | | | | 1,230 | | | Cash and cash equivalents at end of period | | $ | 1,048 | | | | | $ | 1,204 | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part | | | | of these statements. | | | | | | | | | | | | | | | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the StockholdersStockholder and Board of Directors of Ohio Edison Company:
We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of March 31, 2005,2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 20052006 and 2004.2005. 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 as of December 31, 2004,2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004;(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 and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 2(G) 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 711 to those consolidated financial statements) dated March 7, 2005,February 27, 2006, we expressed an unqualified opinions thereon. Theopinion on those consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein.statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004,2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP Cleveland, Ohio May 3, 20058, 2006
OHIO EDISON COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. 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.
FirstEnergy Intra-System Generation Asset Transfers
On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred did not include OE's leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.
On October 24, 2005, the OE Companies completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.
On December 16, 2005, the OE Companies completed the intra-system transfer of their ownership interests in the nuclear generation assets to NGC through an asset spin-off in the form of a dividend. FENOC continues to operate and maintain the nuclear generation assets.
These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.
The transfers will affect the OE Companies' near-term results with reductions in both revenues and expenses. Revenues are reduced due to the termination of certain arrangements with FES, under which the OE Companies previously sold their nuclear-generated KWH to FES and leased their non-nuclear generation assets to FGCO, a subsidiary of FES. Their expenses are lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets. With respect to OE's retained leasehold interests in the Perry Nuclear Power Plant and Beaver Valley Power Station Unit 2. OE has continued the nuclear-generated KWH sales arrangement with FES for the associated output and continues to be obligated on the applicable portion of expenses related to those interests. In addition, the OE Companies receive interest income on associated company notes receivable from the transfer of their generation net assets. FES will continue to provide the OE Companies’ PLR requirements under revised purchased power arrangements for the three-year period beginning January 1, 2006 (see Regulatory Matters).
The effects on the OE Companies' results of operations in the first quarter of 2006 compared to the first quarter of 2005 from the generation asset transfers (also reflecting OE's retained leasehold interests discussed above) are summarized in the following table:
Intra-System Generation Asset Transfers - | First Quarter 2006 vs First Quarter 2005 Income Statement Effects | Increase (Decrease) | | (In millions) | | | Operating Revenues: | | | | Non-nuclear generating units rent | | $ | (45 | ) (a) | Nuclear generated KWH sales | | | (64 | ) (b) | Total - Operating Revenues Effect | | | (109 | ) | | Operating Expenses and Taxes: | | | | | Fuel costs - nuclear | | | (9 | ) (c) | Nuclear operating costs | | | (46 | ) (c) | Provision for depreciation | | | (17 | ) (d) | General taxes | | | (3 | ) (e) | Income taxes | | | (15 | ) (i) | Total - Operating Expenses and Taxes Effect | | | (90 | ) | | Operating Income Effect | | | (19 | ) | | Other Income: | | | | | Interest income from notes receivable | | | 15 | (f) | Nuclear decommissioning trust earnings | | | (2 | ) (g) | Income taxes | | | (5 | ) (i) | Total - Other Income Effect | | | 8 | | | Net Interest Charges: | | | | | Allowance for funds used during construction | | | (2 | ) (h) | Total - Net Interest Charges Effect | | | 2 | | | Net Income Effect | | $ | (13 | ) | | | | | | | (a) Elimination of non-nuclear generation assets lease to FGCO. | | (b) Reduction of nuclear generated wholesale KWH sales to FES. | | (c) Reduction of nuclear fuel and operating costs. | | (d) Reduction of depreciation expense and asset retirement obligation accretion related to generation assets. | | (e) Reduction of property tax expense on generation assets. | | (f) Interest income on associated company notes receivable from the | | transfer of generation net assets. | | (g) Reduction of earnings on nuclear decommissioning trusts. | | (h) Reduction of allowance for borrowed funds used during construction on nuclear capital expenditures. | | (i) Income tax effect of the above adjustments. |
Results of Operations Earnings on common stock in the first quarter of 2005 decreased2006 increased to $56$63 million from $76$56 million in the first quarter of 2004.2005. The increase in earnings decrease in 20052006 primarily resulted from reduced operating revenuesexpenses and other incometaxes and increased nuclear operating costs, which wereother income, partially offset by decreased depreciation, changeslower operating revenues and increased net interest charges principally from the asset transfer effects shown in amortization and deferrals of regulatory assets, lower fuel and purchased power costs, and reduced financing costs.the table above.
Operating Revenues
Operating revenues decreased by $17$140 million or 2.3%19.3% in the first quarter of 20052006 compared with the same period in 2004. Lower2005, primarily due to the generation asset transfer impact summarized in the table above. Excluding the effects of the asset transfer, operating revenues decreased $31 million, primarily resulted from a $24due to decreases of $59 million and $98 million in wholesale sales decreaseand distribution revenues, respectively, partially offset by increases in retail generation and distribution revenues of $6$108 million and $2 million, respectively.reduced customer shopping incentives of $18 million.
Lower The lower wholesale revenues reflected decreasedthe termination of a non-affiliated wholesale sales to FESagreement and the cessation of $28 million (20.3% KWH decrease) due to reduced nuclear generation available for sale. The decreased FESthe MSG sales were partially offset by increased sales of $4 million to non-affiliated customers (primarily MSG sales). Under its Ohioarrangements under OE’s transition plan in December 2005. OE ishad been required to provide the attractively-priced MSG to non-affiliated alternative suppliers (see Outlook - Regulatory Matters).suppliers.
Increased retail generation revenues resulted from increasedin all customer sectors (residential - $43 million; commercial - $32 million; and industrial - $33 million) reflected the impact of higher KWH sales to industrial and commercial customers of $5 million and $3 million, respectively, partially offset by a $2 million residential sales decrease.higher unit prices. The increase in industrial and commercial revenues reflected the effect of higher generation KWH sales (industrial - 4.1% and commercial - 3.9%) and higher composite unit prices. The industrial KWH growth was moderated by increasedprimarily resulted from decreased customer shopping. Generationshopping, as the percentage of generation services provided to industrial customers by alternative suppliers as a percent ofto total industrial sales delivered in OE’sOE's service area increaseddecreased by 2.1 percentage points, which partially offset the effectfollowing percentages: residential - 8.8%; commercial - 11.0%; and industrial - 9.3%. The decreased shopping resulted from alternative energy suppliers terminating their supply arrangements with OE’s shopping customers in the fourth quarter of a 7.2% increase2005. Higher unit prices reflected the Rate Stabilization Charge and fuel recovery rider that became effective in industrial sector deliveries. Reduced residential revenues were principally due to a 2.8% KWH sales decrease reflecting increased residential customer shopping (1.7 percentage point increase). Commercial customer shopping remained relatively unchanged.January 2006 under the RCP.
Revenues from distribution throughput increased $2decreased $98 million in the first quarter of 20052006 compared with the same period in 2004. Distribution deliveries to2006. The decrease in all customer sectors (residential - $40 million; commercial - $32 million; and industrial customers increased by $2 million- $26 million) primarily reflected the impact of lower composite prices and $1 million, respectively,reduced KWH deliveries. The lower unit prices reflected the completion of the generation-related transition cost recovery under OE’s and Penn’s respective rate restructuring plans in 2005, compared to 2004, reflecting increased KWH deliveries partially offset by lower composite unit prices. The increased sales to the commercial and industrial sectors resulted,recovery of MISO costs beginning in part, from an improving economy in OE's service area. Distribution2006 (see Outlook -- Regulatory Matters). Lower distribution KWH deliveries to residential and commercial customers decreased slightly.reflected the impact of milder weather conditions in the first quarter of 2006, compared to the same period of 2005.
Under the Ohio transition plan, OE provideshad provided incentives to customers to encourage switching to alternative energy providers.providers, which reduced OE’s revenues were reduced by $2$18 million from additional credits in the first quarter of 2005 compared to the same period in 2004.2005. These revenue reductions, arewhich were deferred for future recovery under OE’s transition plan and dodid not affect current period earnings. (Seeearnings, ceased in 2006. The deferred shopping incentives (Extended RTC) are now being recovered under the RCP (see Regulatory Matters below.)
Changes in electric generation sales and distribution deliveries in the first quarter of 20052006 from the same quarter of 20042005 are summarized in the following table:
Changes in KWH Sales | | | | Increase (Decrease) | | | | | | | | | Electric Generation: | | | | | Retail | | | 1.311.3 | % | | Wholesale - Non-Associated | | | (17.495.6 | )% | Total Electric Generation SalesWholesale - Associated (FES)* | | | (7.675.7 | )% | Total Electric Generation Sales | | | (28.0 | )% | | | | | | | Distribution Deliveries: | | | | | Residential | | | (0.71.8 | )% | Commercial | | | 3.6(1.0 | )% | Industrial | | | 7.2(1.7 | )% | Total Distribution Deliveries | | | 3.1(1.5 | )% | | | | | | *Change reflects impact of generation asset transfers. | | | | |
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $11$123 million in the first quarter of 20052006 from the first quarter of 2004. The2005 principally due to the effects of the generation asset transfer shown in the table above. Excluding the asset transfer effects, the following table presents changes from the prior year by expense category.
Operating Expenses and Taxes - Changes | | | | | | | Increase (Decrease) | | (In millions) | | | (In millions) | | | | | | | | | Fuel costs | | $ | (3 | ) | | | Purchased power costs | | | (3 | ) | | $ | 26 | | | Nuclear operating costs | | | 16 | | | | (8 | ) | | Other operating costs | | | (2 | ) | | | 7 | | | Provision for depreciation | | | (4 | ) | | | 9 | | | Amortization of regulatory assets | | | (2 | ) | | | (58 | ) | | Deferral of new regulatory assets | | | (6 | ) | | | (1 | ) | | General taxes | | | -- | | | | 1 | | | Income taxes | | | (7 | ) | | | (10 | ) | Net decrease in operating expenses and taxes | | $ | (11 | ) | | Total operating expenses and taxes | | | $ | (34 | ) |
Lower fuel Increased purchased power costs in the first quarter of 2005, compared2006 reflected higher unit prices associated with the same quarter of 2004, resulted from decreased nuclear generation - down 20.3%. Decreased purchasednew power costs reflected lower KWH purchasedsupply agreement with FES, partially offset by higher unit costs. Highera decrease in KWH purchased to meet the lower net generation sales requirements, and RCP fuel deferrals of $11 million. Under the RCP that was effective January 1, 2006, OE can defer increased fuel costs (i.e., in excess of 2002 baseline amounts) above the amount collected through the fuel recovery mechanism. Excluding the effects of the generation asset transfers, the lower nuclear operating costs for OE’s nuclear leasehold interests were primarily due to the absence in 2006 of the Perry nuclear plantNuclear Power Plant scheduled refueling outage (including an unplanned extension) in the first quarter of 2005 and the absence of nuclear refueling outages in the same period last year.2005. The decreaseincrease in other operating costs was primarily duefrom increased transmission expenses related to reduced labor costs and lower employee benefit expenses.MISO Day 2 operations that began on April 1, 2005.
The decrease in Excluding the effects of the generation asset transfers, higher depreciation expense in the first quarter of 20052006 compared with the same quarter of 2004 was attributable2005 reflects capital additions subsequent to revised estimated service life assumptions for fossil generating plants.the first quarter of 2005. Lower amortization of regulatory assets was due to decreasedthe completion of the generation-related transition cost amortization under OE's and Penn's respective transition plans, partially offset by the amortization of Ohio transition regulatory assets, effective April 1, 2004.deferred MISO costs being recovered in 2006. The higher deferrals of new regulatory assets primarily resulted from higherthe deferral of distribution costs and related interest ($19 million) under the RCP, partially offset by the decrease in shopping incentive deferrals ($218 million) and deferredwhich ceased in 2006 under the Ohio transition plan. The deferral of interest on the unamortized shopping incentives ($3 million).incentive balances will continue under the RCP.
Other Income
Other income decreased $16increased $25 million in the first quarter of 20052006 compared with the same quarter of 2004,2005, partially due to the effects of the asset transfer. Excluding the asset transfer effects, the $17 million increase is primarily due to the absence in 2006 of the 2005 accruals of an $8.5 million civil penalty payable to the Department of JusticeDOJ and $10 million for environmental projects in connection with the Sammis PlantNew Source Review settlement (see Outlook - Environmental Matters).
Net Interest Charges
Net interest charges increased $1 million in the first quarter of 2006 compared to the same period of 2005 primarily due to the effects of the generation asset transfer. Excluding the asset transfer, interest charges continued to trend lower, decreasing by $2$1 million in the first quarter of 20052006 compared with the same quarter of 2004, reflecting redemptions of $15 million of outstanding debt during the first quarter of 2005.
Capital Resources and Liquidity
OE’s cash requirements in 20052006 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing OE’s net debtwith cash from operations and preferred stock outstanding.short-term credit arrangements. Available borrowing capacity under credit facilities will be used to manage working capital requirements. Thereafter,
In connection with a plan to realign its capital structure, OE expectsmay also issue up to use$600 million of long-term debt in 2006 with proceeds expected to fund a combinationreturn of cash from operations and funds from theequity capital markets.to FirstEnergy.
Changes in Cash Position
OE's cash and cash equivalents were approximately $1 million as of March 31, 20052006 and December 31, 2004.2005.
Cash Flows From Operating Activities
Cash provided from operating activities during the first quarter of 2006, compared with the first quarter of 2005, and 2004 period were as follows:
| | | | Three Months Ended March 31, | | Operating Cash Flows | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | (In millions) | | | Cash earnings (1) | | $ | 185 | | $ | 231 | | | $ | 120 | | $ | 185 | | | Working capital and other | | | 81 | | | (126 | ) | | | 227 | | | 83 | | | Total Cash Flows from Operating Actitivities | | $ | 266 | | $ | 105 | | | | Net cash provided from operating activities | | | $ | 347 | | $ | 268 | |
(1)Cash earnings isare a non-GAAP measure (see reconciliation below).
Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. FirstEnergyOE believes that cash earnings isare a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.income:
| | | | Three Months Ended March 31, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | (In millions) | | | Net Income (GAAP) | | $ | 57 | | $ | 76 | | | $ | 64 | | $ | 57 | | | Non-Cash Charges (Credits): | | | | | | | | | | | | | | | | Provision for depreciation | | | 26 | | | 30 | | | | 18 | | | 26 | | | Amortization of regulatory assets | | | 112 | | | 114 | | | | 54 | | | 112 | | | Nuclear fuel and capital lease amortization | | | 9 | | | 11 | | | | Deferral of new regulatory assets | | | (25 | ) | | (19 | ) | | | (26 | ) | | (25 | ) | Nuclear fuel and lease amortization | | | | 1 | | | 9 | | Amortization of electric service obligation | | | | (8 | ) | | - | | Amortization of lease costs | | | | 33 | | | 33 | | | Deferred income taxes and investment tax credits, net | | | (25 | ) | | (30 | ) | | | (4 | ) | | (25 | ) | | Other non-cash charges | | | 31 | | | 49 | | | Deferred purchased power costs | | | | (11 | ) | | - | | Accrued compensation and retirement benefits | | | | (1 | ) | | (2 | ) | | Cash earnings (Non-GAAP) | | $ | 185 | | $ | 231 | | | $ | 120 | | $ | 185 | |
Net cash provided from operating activities increased $161$79 million in the first quarter of 2005,2006, compared with the first quarter of 2004,2005, due to a $207$144 million increase from changes in working capital, partially offset by a $46$65 million decrease in cash earnings as described above and under "Results“Results from Operations".Operations.” The increase in working capital primarily reflects changes in accounts payable and receivables from associated companies of $146$80 million and accounts payable to associated companiesprepayments and other current assets of $278$79 million, partially offset by changes in accrued taxes of $356$17 million. The changes for accounts payable and accrued taxes primarily reflect a $249 million reallocation of tax liabilities between associated companies under the tax sharing agreement in 2004.
Cash Flows From Financing Activities Net cash used for financing activities decreasedincreased to $274 million in the first quarter of 2006 from $32 million in the first quarter of 2005 from $105 million in the first quarter of 2004.2005. The decreaseincrease primarily reflected lower debt redemptions andrepayments of short-term borrowings to associated companies, partially offset by a $12 million decrease in common stock dividend payments to FirstEnergy.
OE had approximately $694$583 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $210$23 million of short-term indebtedness as of March 31, 2005.2006. OE has authorization from the PUCO to incur short-term debt of up to $500 million, (includingwhich is expected to come from the bank facilitiesfacility and the utility money pool described below).below. Penn has authorization from the SEC, continued by FERC rules adopted as a result of EPACT's repeal of PUHCA, to incur short-term debt up to its charter limit of $49$43 million (includingas of March 31, 2006, and will have access to the bank facility and the utility money pool). In addition, Penn haspool.
OES Capital is a $25wholly owned subsidiary of OE whose borrowings are secured by customer accounts receivable purchased from OE. OES Capital can borrow up to $170 million under a receivables financing facility.arrangement. As a separate legal entity with separate creditors, OES Capital would have to satisfy its obligations to creditors before any of its remaining assets could be made available to OE. As of March 31, 2005,2006, the facility was undrawn; it expires June 30, 2005 and is expected to be renewed.not drawn.
Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to the full amount of $25 million available as of March 31, 2006 under a receivables financing arrangement which expires June 29, 2006. As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. As of March 31, 2006, the facility was drawn for $19 million.
As of March 31, 2006, OE and Penn had the aggregate capability to issue approximately $1.9 billion$502 million 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 also subject to provisions of its senior note indenturesindenture 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, these provisions would permit OE is permitted under the indenture to incur additional secured debt not otherwise permitted by a specified exception of up to $650$644 million as of March 31, 2005.2006. Based upon applicable earnings coverage tests in their respective charters, OE and Penn could issue a total of $2.9$3.1 billion of preferred stock (assuming no additional debt was issued) as of March 31, 2005.2006.
As of April 26, 2006, a shelf registration statement filed by OE became effective and provides, together with previously effective OE registration statements, $1 billion of capacity to support future issuances of debt securities by OE.
FirstEnergy, OE, has $409Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility with a syndicate of banks that expires in June 2010. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. OE's borrowing limit under the facility is $500 million and Penn’s is $50 million, subject in each case to applicable regulatory approvals.
Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding letters of credit will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under existing credit facilities which were unusedand accounts receivable financing facilities totaled $726 million as of March 31, 2005, consisting of a $125 million three-year facility maturing in October 2006, a syndicated $250 million two-year facility maturing in May 2005 and bank facilities of $34 million. These facilities are intended to provide liquidity to meet OE’s short-term working capital requirements and would be available for investment in the money pool with its regulated affiliates.2006.
Borrowings under these facilities are conditioned on maintaining compliance with certain The revolving credit facility contains financial covenants in the agreements. OE is requiredrequiring each borrower to maintain a consolidated 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 1.65%. As of March 31, 2005, OE’s fixed charge coverage ratio,2006, debt to total capitalization as defined under the revolving credit agreements,facility was 6.87 to 1. OE's debt to total capitalization ratio, as defined under the credit agreements, was 0.40 to 1. The ability to draw on each of its facilities is also conditioned upon33% for OE making certain representations and warranties to the lending banks prior to drawing under the facilities, including a representation that there has been no material adverse change in its business, condition (financial or otherwise), results of operations, or prospects.35% for Penn.
None of OE’s primary credit facilities The facility does not contain any provisions that either restrict itsthe ability of OE and Penn to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Each primary facility does contain "pricing grids"Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to OE’s and Penn’s credit ratings.
OE hasand Penn have the ability to borrow from itstheir regulated affiliates and FirstEnergy to meet itstheir short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 20052006 was 2.66%4.58%.
On April 6, 2004, Ohio Air Quality Development Authority pollution control bonds aggregating $100 million and Ohio Water Development Authority pollution control bonds aggregating $6.45 million, respectively, were refunded. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance and secured by FMB.
On May 16, 2005, Penn intends to redeem all 127,500 outstanding shares of 7.625% preferred stock at $102.29 per share and all 250,000 outstanding shares of 7.75% preferred stock at $100 per share, both plus accrued dividends to the date of redemption.
OE’s access to the capital markets and the costs of financing are dependent oninfluenced by the ratings of its securities and the securities of FirstEnergy.securities. The ratings outlook from the rating agenciesS&P on all such securities is stable.
On March 18, 2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affect FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the The ratings outlook would be revised tofrom Moody's and Fitch on all securities is positive.
In April 2006, pollution control notes that were formerly obligations of OE and Penn were refinanced and became obligations of FGCO and NGC. The proceeds from the refinancings were used to repay a portion of their associated company notes payable to Penn and OE. With those repayments, OE redeemed $74.8 million and Penn redeemed $6.95 million of pollution control notes having variable interest rates.
Cash Flows From Investing Activities Net cash used for investing activities increaseddecreased to $234$73 million in the first quarter of 20052006 from $0.4$235 million in the first quarter of 2004.2005. The increasedecrease resulted primarily from a $203$109 million increase ofdecrease in loans to associated companies and a $42$51 million increasedecrease in property additions.additions, which reflects the impact of the generation asset transfers.
During the remaining three quarters of 2005,2006, capital requirements for property additions and capital leases are expected to be approximately $175 million, including $19 million for nuclear fuel.$93 million. OE has additional requirements of approximately $120$4 million to meet sinking fund requirements for preferred stock and maturing long-term debt (excluding Penn's optional redemptions disclosed above) during the remainder of 2005.2006. These cash requirements are expected to be satisfied from a combination of internal cash, funds raised in the long-term debt capital markets and short-term credit arrangements.
OE’s capital spending for the period 2005-20072006-2010 is expected to be about $667$638 million, (excluding nuclear fuel), of which approximately $216$122 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $145 million, of which about $36 million applies to 2005. During the same period, its nuclear fuel investments are expected to be reduced by approximately $126 million and $40 million, respectively, as the nuclear fuel is consumed.2006.
Off-Balance Sheet Arrangements
Obligations not included on OE’s Consolidated Balance Sheets primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. The present value of these operating lease commitments, net of trust investments, was $688$666 million as of March 31, 2005.2006.
Equity Price Risk
Included in OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $244$71 million and $248$67 million as of March 31, 20052006 and December 31, 2004,2005, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $24$7 million reduction in fair value as of March 31, 2005.2006. Changes in the fair value of these investments are recorded in OCI unless recognized as a result of a sale or recognized as regulatory assets or liabilities.
Outlook The electric industry continues to transition to a more competitive environment and all of the OE Companies’ customers can select alternative energy suppliers. The OE Companies continue to deliver power to residential homes and businesses through their existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, the OE Companies have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
Regulatory Matters
In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of OE's customers elects to obtain power from an alternative supplier, OE reduces the customer's bill with a "generation shopping credit," based on the generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 2005. 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.
OE's revised Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, and continues OE's support of energy efficiency and economic development efforts. Other key components of the revised Rate Stabilization Plan include the following:
· | extension of the amortization period for transition costs being recovered through the RTC for OE from 2006 to as late as 2007; |
· | deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and |
· | ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes. |
On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may require OE to undertake, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. Any acceptance of future competitive bid results would terminate the Rate Stabilization Plan pricing, but not the related approved accounting, and not until twelve months after the PUCO authorizes such termination.
On December 30, 2004, OE filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $14 million in transmission and ancillary service costs beginning January 1, 2006. OE also filed an application for authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ATSI rate increase, as applicable, from October 1, 2003 through December 31, 2005.
OE and Penn record as regulatoryRegulatory assets are costs which have been authorized by the PUCO, the PPUC and the FERC for recovery from customers in future periods and, withoutor for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income whenas incurred. OE’sAll regulatory assets asare expected to be recovered under the provisions of March 31, 2005the OE Companies’ transition plans and December 31, 2004, were $1.0 billion and $1.1 billion, respectively. OE is deferring customer shopping incentives and interest costs as newrate restructuring plans. OE‘s regulatory assets in accordance with its transitionwere $757 million and rate stabilization plans. These regulatory assets total $250$775 million as of March 31, 2006 and December 31, 2005, and 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 during that period. Penn's net regulatory asset components aggregate asrespectively. Penn had net regulatory liabilities of approximately $27$64 million and $18$59 million as of March 31, 2006 and December 31, 2005, respectively, which are included in Other Noncurrent Liabilities on the Consolidated Balance SheetSheets as of March 31, 20052006 and December 31, 2005.
On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO. On August 5, 2004, respectively.the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming that order with respect to the approval of the rate stabilization charge, approval of the shopping credits, the grant of interest on shopping credit incentive deferral amounts, and approval of FirstEnergy’s financial separation plan. It remanded the approval of the RSP pricing back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient customer participation in the competitive marketplace.
Under provisions of the RSP, the PUCO had required the Ohio Companies to undertake a CBP to secure generation and allow for customer pricing participation in the competitive marketplace. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until 12 months after the PUCO authorizes such termination. On December 9, 2004, the PUCO rejected the auction price results from the CBP for the generation supply period beginning January 1, 2006 and issued an entry stating that the pricing under the approved revised RSP would take effect on January 1, 2006. On February 23, 2006 the CBP auction manager, National Economic Research Associates, notified the PUCO that a subsequent CBP to potentially provide firm generation service for the Ohio Companies' 2007 and 2008 actual load requirements could not proceed due to lack of interest, as there were no bidder applications submitted. Additionally, on March 20, 2006, the PUCO denied applications for rehearing filed by various parties regarding the PUCO's rules for the CBP. The above May 3, 2006 Supreme Court of Ohio opinion may require the PUCO to reconsider this customer pricing process.
On January 4, 2006, the PUCO approved, with modifications, OE's RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:
| · | Maintaining the existing level of base distribution rates through December 31, 2008 for OE; |
| · | Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred by all of the Ohio Companies during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years; |
| · | Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for OE; |
| · | Reducing the deferred shopping incentive balance as of January 1, 2006 by up to $75 million for OE by accelerating the application of its accumulated cost of removal regulatory liability; and |
| · | Recovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all OE and TE distribution and transmission customers through a fuel recovery mechanism. The Ohio Companies may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the amount collected through the fuel recovery mechanism (in lieu of implementation of the GCAF rider). |
The following table provides OE’s estimated amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2006 through 2008:
Amortization | | | | Period | | | Amortization | | | | | (In millions) | | 2006 | | $ | 172 | | 2007 | | | 180 | | 2008 | | | 206 | Total Amortization | | $ | 558 |
The PUCO’s January 4, 2006 approval of the RCP also included approval of the Ohio Companies’ supplemental stipulation which was filed with the PUCO on November 4, 2005 and which was an additional component of the RCP filed on September 9, 2005. On January 10, 2006, the Ohio Companies filed a Motion for Clarification of the PUCO order approving the RCP. The Ohio Companies sought clarity on issues related to distribution deferrals, including requirements of the review process, timing for recognizing certain deferrals and definitions of the types of qualified expenditures. The Ohio Companies also sought confirmation that the list of deferrable distribution expenditures originally included in the revised stipulation fall within the PUCO order definition of qualified expenditures. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies’ requests to: | · | Recognize fuel and distribution deferrals commencing January 1, 2006; | | | | | · | Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff; | | | | | · | Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and | | | | | · | Clarify that distribution expenditures do not have to be “accelerated” in order to be deferred. |
The PUCO approved the Ohio Companies’ methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies’ Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. The Ohio Companies responded to the applications for rehearing on February 13, 2006. In an Entry on Rehearing issued by the PUCO on March 1, 2006, all motions for rehearing were denied. Certain of these parties have subsequently filed their notices of appeal with the Supreme Court of Ohio alleging various errors made by the PUCO in its order approving the RCP.
On December 30, 2004, OE filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application sought recovery of these costs beginning January 1, 2006. OE requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues expected to be recovered from January through June 30, 2006 are approximately $34 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. On May 1, 2006, OE filed a modification to the rider to determine revenues from July 2006 through June 2007.
The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for OE to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized OE to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of OE's case with a similar case involving Dayton Power & Light Company. Oral argument is currently scheduled for May 10, 2006. On January 20, 2006, the OCC sought rehearing of the PUCO approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The OCC's brief is expected to be filed during the second quarter of 2006. The briefs of the PUCO and OE will be due within thirty days of the OCC's filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On April 18, 2006, the Court denied both parts of the motion but on its own motion consolidated the OCC's appeal of OE's case with a similar case of Dayton Power & Light Company and stayed briefing on these appeals.
On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn recommended that the RFP process cover the period January 1, 2007 through May 31, 2008. Hearings were held on January 10, 2006 with main briefs filed on January 27, 2006 and reply briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a Recommended Decision to adopt Penn's RFP process with modifications. The PPUC approved the Recommended Decision with additional modifications on April 20, 2006. The approved plan is designed to provide customers with PLR service for January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.
On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies at a price equal to the retail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio competitive bid process results in a lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. The PPUC approved Penn's plan with modifications on April 20, 2006 to use an RFP process to obtain its power supply requirements after 2006.
On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticized the Ohio competitive bid process, and required FES to submit additional evidence in support of the reasonableness of the prices charged in the power sales agreements. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in late January 2007, as a result of the April 20, 2006 extension of the procedural schedule. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order and the FERC granted rehearing for future consideration on March 1, 2006.
See Note 1311 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio and Pennsylvania and a more detailed discussion of reliability initiatives, including actionsinitiatives by the PPUC, that impact Penn.
Environmental Matters
OE accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably determineestimate the amount of such costs. Unasserted claims are reflected in OE'sOE’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
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 March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 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. CAIR will require additional reductions of NOx and SO2 emissions in two phases (Phase I in 2009 for NOx, 2010 for SO2 and Phase II in 2015 for both NOx and SO2). The OE Companies’ Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO2 and NOx emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOx emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOx cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which the OE 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 March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline by 2010 as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. 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 coveringalleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which iswas owned at that time by OE and Penn. In addition, the U.S. Department of Justice (DOJ)DOJ filed eight civil complaints against various investor-owned utilities, which includedincluding 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. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement which is inwas approved by the form of a Consent Decree subject to a thirty-day public comment period that endedCourt on April 29,July 11, 2005, and final approval by the District Court Judge, requires OEreductions of NOX and Penn to reduceSO2 emissions fromat the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices requiring capitaland provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if OE and Penn fail to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, OE and Penn could be exposed to penalties under the settlement agreement. Capital expenditures necessary to meet those requirements are currently estimated to be $1.1$1.5 billion (primarily(the primary portion of which is expected to be spent in the 2008 to 2011 time period).The. On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million towardstoward environmentally beneficial projects, which include wind energy purchasepurchased power agreements over a 20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 includeincluded the penalties payablepaid by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also accruedrecognized liabilities in the first quarter of 2005 of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects during the first quarter of 2005.projects.
Climate ChangeIn 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 United States 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 percent through 2012.71
The OE 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 KWH of electricity generated by the OE Companies is lower than many regional competitors due to the OE Companies' diversified generation sources which include low or non-CO2 emitting gas-fired and nuclear generators.
FirstEnergy plans to issue a report that will disclose the Companies’ environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by December 1, 2005 and will post the report on its web site,www.firstenergycorp.com.
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.
See Note 12(B)10(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.
Other Legal Proceedings
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to OE'sOE’s normal business operations pending against OE and its subsidiaries. The most significantother potentially material items not otherwise discussed above are described below.
Power Outages and Related Litigation-
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. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,concluded, 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 real-time 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 contained 46 "recommendations“recommendations to prevent or minimize the scope of future blackouts."” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in process,new or material upgrades to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother applicable government agencies and reliability coordinators may, however, 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 asFinally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of March 31, 2005 forcontrol room operators before determining the next steps, if any, expenditures in excess of those actually incurred through that date.the proceeding.
Three substantially similar actionsFirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in various Ohio State courts by plaintiffs seekingbut were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent customers whoothers as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of the four cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc. as well) for claims paid to insureds for damages allegedly suffered damagesarising as a result of the loss of power on August 14, 2003 power outages. All three2003. The listed insureds in these cases, werein many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. On March 7, 2006, the PUCO issued a ruling applicable to all pending cases. Among its various rulings, the PUCO consolidated all of the pending outage cases for hearing; limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence; and gave the plaintiffs additional time to amend their complaints to otherwise comply with the PUCO’s underlying order. The plaintiffs in one case have since filed an amended complaint. The named FirstEnergy companies have answered and also have filed a motion to dismiss the action, which is pending. Also, most complainants, along with the FirstEnergy companies, filed applications for lackrehearing with the PUCO over various rulings contained in the March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow the insurance company claimants, as insurers, to prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities which provide their service. The PUCO denied all other motions for rehearing. No estimate of jurisdiction. One case was refiled on January 12, 2004 at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. In the remaining case, the Courtpotential liability is available for any of Appeals on March 31, 2005 affirmed the trial court’s decision dismissing the case. It is not yet known whether further appeal will be sought.these cases. In addition to the one case that was refiled at the PUCO,these six cases, 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 Following the PUCO's March 7, 2006 order, that action was filed on August 25, 2004 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 timetable for a decision on the motion to dismiss has been establishedvoluntarily dismissed by the Court. No damage estimate has been provided and thus potential liability has not been determined.claimants.
FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against 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-
As of December 16, 2005, NGC acquired ownership of the nuclear generation assets transferred from OE, Penn, CEI and TE with the exception of leasehold interests of OE and TE in certain of the nuclear plants that are subject to sale and leaseback arrangements with non-affiliates. Excluding OE's retained leasehold interests in Beaver Valley Unit 2 (21.66%) and Perry (12.58%), the transfer included the OE Companies’ prior owned interests in Beaver Valley Unit 1 (100%), Beaver Valley Unit 2 (33.96%) and Perry (22.66%).
On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the pastpreceding two years.years and the licensee's failure to take prompt and corrective action. FENOC operates the Perry Nuclear Power Plant, in which the OE Companies have a 35.24% interest. Plant.
On April 4, 2005, the NRC held a public forummeeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives althougheven though it remained under the heightened NRC oversight since August 2004.oversight. During the public forummeeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. By an inspection report dated January 18, 2006, the NRC closed one of the White Findings (related to emergency preparedness) which led to the multiple degraded cornerstones.
On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's 2005 annual assessment letter dated March 2, 2006 and associated meetings to discuss the performance of Perry on March 14, 2006, the NRC again stated that the Perry Plant continued to operate in a manner that "preserved public health and safety." However, the NRC also stated that increased levels of regulatory oversight would continue until sustained improvement in the performance of the facility was realized. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these mattersAlthough FirstEnergy is unable to predict the impact of the ultimate disposition of this matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.condition, results of operations and cash flows.
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,the Ohio Companies, and the Davis-Besse extended outage, (OE has no interest in Davis-Besse), have 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. On December 30, 2004, FirstEnergy received a second subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse related disclosures, which FirstEnergy has provided. FirstEnergy has cooperated fully with the informal inquiry and will continuecontinues to do so with the formal investigation. On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.
The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly-formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO of a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will decide this case.
If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matter,matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, and results of operations.operations and cash flows.
See Note 12(C)10(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.
New Accounting Standards and Interpretations
FIN 47,“AccountingEITF Issue 04-13, "Accounting for Conditional Asset Retirement Obligations - an interpretationPurchases and Sales of FASB Statement No. 143”Inventory with the Same Counterparty"
On March 30, 2005, the FASB issued this interpretation to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. FirstEnergy is currently evaluating the effect this standard will have on the financial statements.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
In March 2004,September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus on the application guidancethat an exchange of inventory should be accounted 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 valuevalue. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and the impairment loss recognizedother storable inventory. Therefore, OE will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective forinterim or annual periods beginning after JuneMarch 15, 2004, were delayed by the issuance of FSP2006. This EITF 03-1-1 in September 2004. During the period of delay, FirstEnergyissue will continue to evaluate its investments as required by existing authoritative guidance.not have a material impact on OE's financial results.
SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140”
In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. OE is currently evaluating the impact of this Statement on its financial statements. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | (Unaudited) | | (Unaudited) | | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | | | | | | March 31, | | | Three Months Ended | | | | | | | | | | | | March 31, | | | | | | | 2005 | | 2004 | | | | | | | | | | | | | | | | | 2006 | | 2005 | | STATEMENTS OF INCOME | | | | (In thousands) | | | (In thousands) | | | | | | | | | | | | | | | | OPERATING REVENUES | | | | | $ | 433,173 | | $ | 426,535 | | | $ | 407,810 | | $ | 433,173 | | | | | | | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | | | Fuel | | | | | 18,327 | | 17,196 | | | | 13,563 | | | 18,327 | | | Purchased power | | | | | 142,884 | | 134,677 | | | | 135,990 | | | 142,884 | | | Nuclear operating costs | | | | | 58,727 | | 32,715 | | | | - | | | 58,727 | | | Other operating costs | | | | | 63,573 | | 64,027 | | | | 72,895 | | | 63,573 | | | Provision for depreciation | | | | | 31,115 | | 32,188 | | | | 17,201 | | | 31,115 | | | Amortization of regulatory assets | | | | | 54,026 | | 48,068 | | | | 31,530 | | | 54,026 | | | Deferral of new regulatory assets | | | | | (25,288 | ) | | (18,480 | ) | | | (22,746 | ) | | (25,288 | ) | | General taxes | | | | | 38,887 | | 38,818 | | | | 35,070 | | | 38,887 | | | Income taxes | | | | | | 4,877 | | | 4,013 | | | | 36,125 | | | 4,877 | | | Total operating expenses and taxes | | | | | | 387,128 | | | 353,222 | | | | 319,628 | | | 387,128 | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | | | 46,045 | | 73,313 | | | | 88,182 | | | 46,045 | | | | | | | | | | | | | | | | | | | OTHER INCOME (net of income taxes) | | | | | 4,304 | | 11,727 | | | | 18,290 | | | 4,304 | | | | | | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | | | | | | Interest on long-term debt | | | | | 27,952 | | 32,211 | | | | 27,185 | | | 27,952 | | | Allowance for borrowed funds used during construction | | | | | 411 | | (1,711 | ) | | | (673 | ) | | 411 | | | Other interest expense | | | | | | 6,514 | | | 6,065 | | | | 7,547 | | | 6,514 | | | Net interest charges | | | | | 34,877 | | 36,565 | | | | 34,059 | | | 34,877 | | | | | | | | | | | | | | | | | | | NET INCOME | | | | | 15,472 | | 48,475 | | | | 72,413 | | | 15,472 | | | | | | | | | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | | | | 2,918 | | | 1,744 | | | | - | | | 2,918 | | | | | | | | | | | | | | | | | | | EARNINGS ON COMMON STOCK | | | | | $ | 12,554 | | $ | 46,731 | | | $ | 72,413 | | $ | 12,554 | | | | | | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | | | | $ | 15,472 | | $ | 48,475 | | | $ | 72,413 | | $ | 15,472 | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | Unrealized gain (loss) on available for sale securities | | | | | (1,221 | ) | | 8,048 | | | | Income tax related to other comprehensive income | | | | | | 504 | | | (3,296 | ) | | | Other comprehensive income (loss), net of tax | | | | | | (717 | ) | | 4,752 | | | | Unrealized loss on available for sale securities | | | | - | | | (1,221 | ) | | Income tax benefit related to other comprehensive income | | | | - | | | 504 | | | Other comprehensive loss, net of tax | | | | - | | | (717 | ) | | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | | | | $ | 14,755 | | $ | 53,227 | | | $ | 72,413 | | $ | 14,755 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral | | | | part of these statements. | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric | | | | | | | | | | Illuminating Company are an integral part of these statements. | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | | | March 31, | | December 31, | | | | | | | 2005 | | 2004 | | | | | | | (In thousands) | | ASSETS | | | | | | | | UTILITY PLANT: | | | | | | | | | In service | | | | | $ | 4,438,471 | | $ | 4,418,313 | | | Less - Accumulated provision for depreciation | | | | | | 1,984,240 | | | 1,961,737 | | | | | | | | | 2,454,231 | | | 2,456,576 | | | Construction work in progress- | | | | | | | | | | | | Electric plant | | | | | | 86,276 | | | 85,258 | | | Nuclear fuel | | | | | | 39,655 | | | 30,827 | | | | | | | | | 125,931 | | | 116,085 | | | | | | | | | 2,580,162 | | | 2,572,661 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | Investment in lessor notes | | | | | | 564,175 | | | 596,645 | | | Nuclear plant decommissioning trusts | | | | | | 391,857 | | | 383,875 | | | Long-term notes receivable from associated companies | | | | | | 7,222 | | | 97,489 | | | Other | | | | | | 16,042 | | | 17,001 | | | | | | | | | 979,296 | | | 1,095,010 | | CURRENT ASSETS: | | | | | | | | | | | | Cash and cash equivalents | | | | | | 207 | | | 197 | | | Receivables- | | | | | | | | | | | | Customers | | | �� | | | 14,233 | | | 11,537 | | | Associated companies | | | | | | 6,277 | | | 33,414 | | | Other (less accumulated provisions of $207,000 and $293,000, respectively, | | | | | | | | | | | | for uncollectible accounts) | | | | | | 92,336 | | | 152,785 | | | Notes receivable from associated companies | | | | | | -- | | | 521 | | | Materials and supplies, at average cost | | | | | | 81,258 | | | 58,922 | | | Prepayments and other | | | | | | 1,509 | | | 2,136 | | | | | | | | | 195,820 | | | 259,512 | | DEFERRED CHARGES: | | | | | | | | | | | | Goodwill | | | | | | 1,693,629 | | | 1,693,629 | | | Regulatory assets | | | | | | 925,473 | | | 958,986 | | | Property taxes | | | | | | 77,792 | | | 77,792 | | | Other | | | | | | 44,648 | | | 32,875 | | | | | | | | | 2,741,542 | | | 2,763,282 | | | | | | | | $ | 6,496,820 | | $ | 6,690,465 | | CAPITALIZATION AND LIABILITIES | | | | | | | | | | | CAPITALIZATION: | | | | | | | | | | | | Common stockholder's equity- | | | | | | | | | | | | Common stock, without par value, authorized 105,000,000 shares - | | | | | | | | | | | | 79,590,689 shares outstanding | | | | | $ | 1,281,962 | | $ | 1,281,962 | | | Accumulated other comprehensive income | | | | | | 17,142 | | | 17,859 | | | Retained earnings | | | | | | 511,288 | | | 553,740 | | | Total common stockholder's equity | | | | | | 1,810,392 | | | 1,853,561 | | | Preferred stock | | | | | | -- | | | 96,404 | | | Long-term debt and other long-term obligations | | | | | | 1,953,089 | | | 1,970,117 | | | | | | | | | 3,763,481 | | | 3,920,082 | | CURRENT LIABILITIES: | | | | | | | | | | | | Currently payable long-term debt | | | | | | 81,382 | | | 76,701 | | | Accounts payable- | | | | | | | | | | | | Associated companies | | | | | | 191,057 | | | 150,141 | | | Other | | | | | | 7,593 | | | 9,271 | | | Notes payable to associated companies | | | | | | 470,732 | | | 488,633 | | | Accrued taxes | | | | | | 108,256 | | | 129,454 | | | Accrued interest | | | | | | 34,133 | | | 22,102 | | | Lease market valuation liability | | | | | | 60,200 | | | 60,200 | | | Other | | | | | | 32,312 | | | 61,131 | | | | | | | | | 985,665 | | | 997,633 | | NONCURRENT LIABILITIES: | | | | | | | | | | | | Accumulated deferred income taxes | | | | | | 535,908 | | | 540,211 | | | Accumulated deferred investment tax credits | | | | | | 59,569 | | | 60,901 | | | Asset retirement obligation | | | | | | 276,627 | | | 272,123 | | | Retirement benefits | | | | | | 81,828 | | | 82,306 | | | Lease market valuation liability | | | | | | 653,200 | | | 668,200 | | | Other | | | | | | 140,542 | | | 149,009 | | | | | | | | | 1,747,674 | | | 1,772,750 | | COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | | | | | | | | $ | 6,496,820 | | $ | 6,690,465 | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these balance sheets. | | | | | | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | March 31, | | December 31, | | | | | 2006 | | 2005 | | | | | (In thousands) | | ASSETS | | | | | | UTILITY PLANT: | | | | | | | In service | | $ | 2,055,348 | | $ | 2,030,935 | | | Less - Accumulated provision for depreciation | | | 799,281 | | | 788,967 | | | | | | 1,256,067 | | | 1,241,968 | | | Construction work in progress | | | 59,756 | | | 51,129 | | | | | | 1,315,823 | | | 1,293,097 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Investment in lessor notes | | | 519,618 | | | 564,166 | | | Long-term notes receivable from associated companies | | | 1,058,626 | | | 1,057,337 | | | Other | | | 12,779 | | | 12,840 | | | | | | 1,591,023 | | | 1,634,343 | | CURRENT ASSETS: | | | | | | | | | Cash and cash equivalents | | | 217 | | | 207 | | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $5,431,000 and $5,180,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 250,546 | | | 268,427 | | | Associated companies | | | 42,435 | | | 86,564 | | | Other | | | 3,958 | | | 16,466 | | | Notes receivable from associated companies | | | 28,535 | | | 19,378 | | | Prepayments and other | | | 1,388 | | | 1,903 | | | | | | 327,079 | | | 392,945 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 1,688,521 | | | 1,688,966 | | | Regulatory assets | | | 857,683 | | | 862,193 | | | Prepaid pension costs | | | 138,047 | | | 139,012 | | | Property taxes | | | 63,500 | | | 63,500 | | | Other | | | 39,874 | | | 27,614 | | | | | | 2,787,625 | | | 2,781,285 | | | | | $ | 6,021,550 | | $ | 6,101,670 | | CAPITALIZATION AND LIABILITIES | | | | | | | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity- | | | | | | | | | Common stock, without par value, authorized 105,000,000 shares - | | | | | | | | | 79,590,689 shares outstanding | | $ | 1,355,897 | | $ | 1,354,924 | | | Retained earnings | | | 596,563 | | | 587,150 | | | Total common stockholder's equity | | | 1,952,460 | | | 1,942,074 | | | Long-term debt and other long-term obligations | | | 1,887,074 | | | 1,939,300 | | | | | | 3,839,534 | | | 3,881,374 | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | | 118,370 | | | 75,718 | | | Short-term borrowings- | | | | | | | | | Associated companies | | | 209,647 | | | 212,256 | | | Other | | | 94,000 | | | 140,000 | | | Accounts payable- | | | | | | | | | Associated companies | | | 64,853 | | | 74,993 | | | Other | | | 5,380 | | | 4,664 | | | Accrued taxes | | | 137,178 | | | 121,487 | | | Accrued interest | | | 31,688 | | | 18,886 | | | Lease market valuation liability | | | 60,200 | | | 60,200 | | | Other | | | 30,750 | | | 61,308 | | | | | | 752,066 | | | 769,512 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 555,320 | | | 554,828 | | | Accumulated deferred investment tax credits | | | 23,001 | | | 23,908 | | | Lease market valuation liability | | | 593,000 | | | 608,000 | | | Asset retirement obligation | | | 8,117 | | | 8,024 | | | Retirement benefits | | | 83,641 | | | 83,414 | | | Deferred revenues - electric service programs | | | 67,205 | | | 71,261 | | | Other | | | 99,666 | | | 101,349 | | | | | | 1,429,950 | | | 1,450,784 | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | $ | 6,021,550 | | $ | 6,101,670 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral | | | part of these balance sheets. | | | | | | | | | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | March 31, | | | | | | | | | | | | | | | | 2005 | | 2004 | | | | | | | | | | | | | | | | (In thousands) | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | Net income | | | | | $ | 15,472 | | $ | 48,475 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | | | Provision for depreciation | | | | | | 31,115 | | | 32,188 | | | Amortization of regulatory assets | | | | | | 54,026 | | | 48,068 | | | Deferral of new regulatory assets | | | | | | (25,288 | ) | | (18,480 | ) | | Nuclear fuel and capital lease amortization | | | | | | 4,610 | | | 5,107 | | | Amortization of electric service obligation | | | | | | (5,451 | ) | | (4,723 | ) | | Deferred rents and lease market valuation liability | | | | | | (53,469 | ) | | (41,635 | ) | | Deferred income taxes and investment tax credits, net | | | | | | (4,506 | ) | | (4,039 | ) | | Accrued retirement benefit obligations | | | | | | (478 | ) | | 5,732 | | | Accrued compensation, net | | | | | | (2,725 | ) | | 1,453 | | | Decrease (Increase) in operating assets- | | | | | | | | | | | | Receivables | | | | | | 84,890 | | | 143,766 | | | Materials and supplies | | | | | | (22,336 | ) | | (2,355 | ) | | Prepayments and other current assets | | | | | | 627 | | | 1,895 | | | Increase (Decrease) in operating liabilities- | | | | | | | | | | | | Accounts payable | | | | | | 39,238 | | | 22,387 | | | Accrued taxes | | | | | | (21,198 | ) | | (67,926 | ) | | Accrued interest | | | | | | 12,031 | | | 8,239 | | | Other | | | | | | (3,358 | ) | | (29,788 | ) | | Net cash provided from operating activities | | | | | | 103,200 | | | 148,364 | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | New Financing- | | | | | | | | | | | | Long-term debt | | | | | | -- | | | 80,967 | | | Redemptions and Repayments- | | | | | | | | | | | | Preferred stock | | | | | | (97,900 | ) | | -- | | | Long-term debt | | | | | | (330 | ) | | (7,985 | ) | | Short-term borrowings, net | | | | | | (29,683 | ) | | (182,167 | ) | | Dividend Payments- | | | | | | | | | | | | Common stock | | | | | | (55,000 | ) | | (55,000 | ) | | Preferred stock | | | | | | (2,260 | ) | | (1,744 | ) | | Net cash used for financing activities | | | | | | (185,173 | ) | | (165,929 | ) | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | Property additions | | | | | | (33,683 | ) | | (17,868 | ) | | Loan repayments from (loans to) associated companies, net | | | | | | 90,788 | | | (2,922 | ) | | Investments in lessor notes | | | | | | 32,470 | | | 20,965 | | | Contributions to nuclear decommissioning trusts | | | | | | (7,256 | ) | | (7,256 | ) | | Other | | | | | | (336 | ) | | 64 | | | Net cash provided from (used for) investing activities | | | | | | 81,983 | | | (7,017 | ) | | | | | | | | | | | | | | Net increase (decrease) in cash and cash equivalents | | | | | | 10 | | | (24,582 | ) | | Cash and cash equivalents at beginning of period | | | | | | 197 | | | 24,782 | | | Cash and cash equivalents at end of period | | | | | $ | 207 | | $ | 200 | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part | | | of these statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | March 31, | | | | | | | 2006 | | 2005 | | | | | | | (In thousands) | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | Net income | | | | | $ | 72,413 | | $ | 15,472 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | | | Provision for depreciation | | | | | | 17,201 | | | 31,115 | | | Amortization of regulatory assets | | | | | | 31,530 | | | 54,026 | | | Deferral of new regulatory assets | | | | | | (22,746 | ) | | (25,288 | ) | | Nuclear fuel and capital lease amortization | | | | | | 60 | | | 4,610 | | | Deferred rents and lease market valuation liability | | | | | | (54,821 | ) | | (53,469 | ) | | Deferred income taxes and investment tax credits, net | | | | | | (402 | ) | | (4,506 | ) | | Deferred purchased power costs | | | | | | (7,780 | ) | | - | | | Accrued compensation and retirement benefits | | | | | | (172 | ) | | (3,203 | ) | | Decrease (increase) in operating assets- | | | | | | | | | | | | Receivables | | | | | | 74,518 | | | 84,890 | | | Materials and supplies | | | | | | - | | | (22,336 | ) | | Prepayments and other current assets | | | | | | 515 | | | 627 | | | Increase (decrease) in operating liabilities- | | | | | | | | | | | | Accounts payable | | | | | | (9,424 | ) | | 39,238 | | | Accrued taxes | | | | | | 15,691 | | | (21,198 | ) | | Accrued interest | | | | | | 12,802 | | | 12,031 | | | Electric service prepayment programs | | | | | | (4,056 | ) | | (5,451 | ) | | Other | | | | | | 81 | | | (3,358 | ) | | Net cash provided from operating activities | | | | | | 125,410 | | | 103,200 | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | Redemptions and Repayments- | | | | | | | | | | | | Preferred stock | | | | | | - | | | (97,900 | ) | | Long-term debt | | | | | | (172 | ) | | (330 | ) | | Short-term borrowings, net | | | | | | (57,760 | ) | | (29,683 | ) | | Dividend Payments- | | | | | | | | | | | | Common stock | | | | | | (63,000 | ) | | (55,000 | ) | | Preferred stock | | | | | | - | | | (2,260 | ) | | Net cash used for financing activities | | | | | | (120,932 | ) | | (185,173 | ) | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | Property additions | | | | | | (34,410 | ) | | (33,683 | ) | | Loan repayments from (loans to) associated companies, net | | | | | | (9,158 | ) | | 90,788 | | | Investments in lessor notes | | | | | | 44,548 | | | 32,470 | | | Proceeds from nuclear decommissioning trust fund sales | | | | | | - | | | 132,805 | | | Investments in nuclear decommissioning trust funds | | | | | | - | | | (140,061 | ) | | Other | | | | | | (5,448 | ) | | (336 | ) | | Net cash provided from (used for) investing activities | | | | | | (4,468 | ) | | 81,983 | | | | | | | | | | | | | | | Net increase in cash and cash equivalents | | | | | | 10 | | | 10 | | | Cash and cash equivalents at beginning of period | | | | | | 207 | | | 197 | | | Cash and cash equivalents at end of period | | | | | $ | 217 | | $ | 207 | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company | | | | | are an integral part of these statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the StockholdersStockholder and Board of Directors of The Cleveland Electric Illuminating Company:
We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of March 31, 2005,2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 20052006 and 2004.2005. 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 as of December 31, 2004,2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004;(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 and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 2(G) and Note 11 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 March 7, 2005,February 27, 2006, we expressed an unqualified opinions thereon. Theopinion on those consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. statements.
In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004,2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP Cleveland, Ohio May 3, 20058, 2006
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in portions of Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI providesCEI’s 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 primarily provided by FES --- an affiliated company.
FirstEnergy Intra-System Generation Asset Transfers
On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively.
On October 24, 2005, CEI completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.
On December 16, 2005, CEI completed the intra-system transfer of their ownership interests in the nuclear generation assets to NGC through a sale at net book value. FENOC continues to operate and maintain the nuclear generation assets.
These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.
The transfers will affect CEI’s near-term results with reductions in both revenues and expenses. Revenues are reduced due to the termination of certain arrangements with FES, under which CEI previously sold its nuclear-generated KWH to FES and leased its non-nuclear generation assets to FGCO, a subsidiary of FES. CEI’s expenses are lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets.With respect to CEI's retained leashold interests in the Bruce Mansfield Plant, CEI has continued the fossil generation KWH sales arrangement with FES and continues to be obligated on the applicable portion of expenses related to those interests. In addition, CEI receives interest income on associated company notes receivable from the transfer of its generation net assets. FES will continue to provide CEI’s PLR requirements under revised purchased power arrangements for the three-year period beginning January 1, 2006 (see Regulatory Matters).
The effects on CEI’s results of operations in the first quarter of 2006 compared to the first quarter of 2005 from the generation asset transfers (also reflecting CEI's retained leasehold interests discussed above) are summarized in the following table:
Intra-System Generation Asset Transfers - | First Quarter 2006 vs First Quarter 2005 Income Statement Effects | Increase (Decrease) | | (In millions) | | | | | | | Operating Revenues: | | | | Non-nuclear generating units rent | | $ | (15 | ) (a) | Nuclear generated KWH sales | | | (53 | ) (b) | Total - Operating Revenues Effect | | | (68 | ) | | Operating Expenses and Taxes: | | | | | Fuel costs - nuclear | | | (6 | ) (c) | Nuclear operating costs | | | (58 | ) (c) | Provision for depreciation | | | (19 | ) (d) | General taxes | | | (4 | ) (e) | Income taxes | | | 8 | (i) | Total- Operating Expenses and Taxes Effect | | | (79 | ) | | Operating Income Effect | | | 11 | | | Other Income: | | | | | Interest income from notes receivable | | | 16 | (f) | Nuclear decommissioning trust earnings | | | (2 | ) (g) | Income taxes | | | (6 | ) (i) | Total-Other Income Effect | | | 8 | | | Net Interest Charges: | | | | | Allowance for funds used during construction | | | 1 | (h) | Total-Net Interest Charges Effect | | | (1 | ) | | Net Income Effect | | $ | 20 | | | | | | | | (a) Elimination of non-nuclear generation assets lease to FGCO. | | (b) Reduction of nuclear generated wholesale KWH sales to FES. | | (c) Reduction of nuclear fuel and operating costs. | | (d) Reduction of depreciation expense and asset retirement obligation accretion related to generation assets. | | (e) Reduction of property tax expense on generation assets. | | (f) Interest income on associated company notes receivable from the transfer of generation net assets. | | (g) Reduction of earnings on nuclear decommissioning trusts. | | (h) Absence in 2006 of adjustment to 2005 allowance for borrowed funds used during construction on generation assets transferred. | | (i) Income tax effect of the above adjustments. |
Results of Operations
Earnings on common stock in the first quarter of 2005 decreased2006 increased to $13$72 million from $47$13 million in the first quarter of 2004.2006. This decreaseincrease resulted principallyprimarily from higher nuclearlower operating expenses and purchased power costs,taxes and increased other income, partially offset by higherlower operating revenues. These changes were principally a result of the effects of the generation asset transfer shown in the table above. Operating Revenues
Operating revenues increaseddecreased by $7$25 million or 1.6%5.9% in the first quarter of 20052006 from the same period in 2004. Higher2005. Excluding the generation asset transfer effects discussed above, operating revenues resulted principally from increased $43 million due to an $88 million increase in retail generation sales revenue of $6revenues and a $19 million (commercialreduction in customer shopping incentives, partially offset by a $44 million decrease in distribution revenues and an $18 million decrease in MSG wholesale sales.
Retail generation revenues increased $88 million (residential - $1$38 million, commercial - $32 million and industrial - $5$18 million).
Retail due to increased KWH sales and higher unit prices. The higher unit prices reflected the rate stabilization charge that became effective in January 2006 under the RCP. The increase in generation KWH sales declined slightly and were not materially affected byresulted from decreased customer shopping as generationshopping. Generation services provided by alternative suppliers as a percent of total sales deliveries in CEI's service area remained relatively constantdecreased in all customer classes by the following percentage points: residential - 59.2%, commercial - 38.9% and industrial - 6.3%. The decreased shopping resulted from alternative energy suppliers terminating their supply arrangements with CEI's shopping customers in the firstfourth quarter of 2005 compared to 2004. The industrial revenue increase was primarily2005.
Non-affiliated wholesale sales revenues decreased by $18 million due to higher unit prices partially offset by the effectcessation of a 1.8% KWHthe MSG sales decrease. The increasearrangements under CEI’s transition plan in commercial sector revenues was primarily dueDecember 2005. CEI had been required to a 3.3% KWH sales increase. Residential retail generation revenues were nearly unchanged forprovide the first quarter of 2005 as comparedMSG to last year.non-affiliated alternative suppliers.
Wholesale sale revenues showed a slight increase of $0.4 million while reflecting the effect of a net 2.8% decrease in KWH sales. MSG wholesale sales to non-affiliated customers increased by $8.2 million (38% KWH sales increase). Under its Ohio transition plan, CEI is required to provide a low-cost generation power supply to unaffiliated alternative suppliers (see Outlook - Regulatory Matters). The MSG sales increase was partially offset by decreased sales to FES of $7.8 million (6.9% KWH decrease) due to less nuclear generation available for sale.
Revenues from distribution throughput decreased by $5$44 million in the first quarter of 20052006 compared with the corresponding quarter in 2004.2005. The decrease was due to lower residentialin all customer classes (residential - $5 million, commercial - $22 million and industrial revenues ($3 million and $4 million, respectively) reflecting- $17 million) primarily reflected lower composite unit prices and reduceddecreased KWH deliveries. The lower unit prices reflected the completion of the generation-related transition cost recovery under CEI’s transition plan in 2005, partially offset by the recovery of MISO costs beginning in 2006 (see Outlook -- Regulatory Matters). The lower KWH distribution deliveries to residential and commercial customers reflected the impact of milder weather conditions in the first quarter of 2005. These impacts were partially offset by higher commercial sector sales2006 compared to the same period of $2 million resulting from increased distribution deliveries partially offset by lower unit prices.2005.
Under the Ohio transition plan, CEI provideshad provided incentives to customers to encourage switching to alternative energy providers, - $1 million of additional credits were provided to customers in the first quarter of 2005 compared with 2004.reducing CEI's revenues. These revenue reductions, arewhich were deferred for future recovery under CEI's transition plan and dodid not affect current period earnings. Other operating revenues increased by $6earnings, ceased in 2006, resulting in a $19 million in the first quarter of 2005 compared with 2004, primarily due to increased revenues from the sales of its customer receivables (see Off-Balance Sheet Arrangements).revenue increase as discussed above.
Changes in electric generation sales and distribution deliveries in the first quarter of 20052006 from the first quarter of 20042005 are summarized in the following table:
Changes in KWH Sales | | | | Increase (Decrease) | | | | | Electric Generation: | | | | Retail | | | (0.646.5 | )% | WholesaleWholesale:
| | | | | Non-Associated Companies | | | (2.894.5 | )% | Associated Companies(1) | | | (64.6 | )% | Total Electric Generation Sales | | | (1.813.9 | )% | | | | | | | Distribution Deliveries: | | | | | Residential | | | (3.32.3 | )% | Commercial | | | 5.5(5.7 | )% | Industrial | | | (2.43.7 | )% | Total Distribution Deliveries | | | (0.73.8 | )% |
(1)Change reflects impact of generation asset transfers.
Operating Expenses and Taxes
Total operating expenses and taxes increaseddecreased by $34$68 million in the first quarter of 20052006 from the firstsame quarter of 2004. The2005 principally due to the asset transfer effects as shown in the table above. Excluding the asset transfer effects, the following table presents changes from the prior year by expense category.category:
Operating Expenses and Taxes - Changes | | | | | | | | | | (In millions) | | | Increase (Decrease) | | | | | (In millions) | | | Fuel costs | | $ | 1 | | | $ | 1 | | | Purchased power costs | | | 8 | | | | (7 | ) | | Nuclear operating costs | | | 26 | | | | Other operating costs | | | | 9 | | | Provision for depreciation | | | (1 | ) | | | 5 | | | Amortization of regulatory assets | | | 6 | | | | (22 | ) | | Deferral of new regulatory assets | | | (7 | ) | | | 3 | | | Income taxes | | | 1 | | | | 23 | | Net increase in operating expenses and taxes | | $ | 34 | | | Total operating expenses and taxes | | | $ | 12 | |
Higher Lower purchased power costs in the first quarter of 2005, compared with the first quarter of 2004, reflected higher KWH purchased, partially offset by lower unit costs. The increase in nuclear operating costs for the first quarter of 20052006 compared to the first quarter of 2004 was2005 primarily due to a refueling outage (including an unplanned extension) atreflected lower unit prices associated with the Perry nuclear plantnew power supply agreement with FES, RCP fuel deferral of $8 million and a mid-cycle inspection outage atpurchased power lease credit amortization of $8 million. Under the Davis-BesseRCP that was effective January 1, 2006, CEI can defer increased fuel costs (i.e., in excess of 2002 baseline amounts). The amortization is for the above-market lease liability related to an existing Beaver Valley Unit 2 purchased power arrangement with TE. The lease credit amortization had been previously included in CEI's nuclear plantoperating costs and the related nuclear generation KWH purchased from TE had then been sold to FES. Subsequent to the generation asset transfer, CEI now retains this purchased power from TE to meet a portion of its PLR obligation and, consequently, the lease amortization is now included as part of CEI's purchased power costs. These decreases were partially offset by the impact of an increase in KWH purchased to meet the first quarter of 2005 and no scheduled outages in the first quarter of 2004.higher retail generation sales requirements. Higher other operating costs reflect increased transmission expenses, primarily related to MISO Day 2 operations that began on April 1, 2005.
The decrease Excluding the effects of the generation asset transfers, the increase in depreciation in the first quarter of 20052006 compared with the first quarter of 20042005 was attributable to revised estimated service life assumptions for fossil generating plants. Highera higher level of depreciable distribution property in 2006. Lower amortization of regulatory assets reflected the completion of generation-related transition cost amortization under CEI’s transition plan, partially offset by the amortization of deferred MISO costs that are being recovered in 2005 as compared to 20042006. The decreased deferral of new regulatory assets was primarily due to increased amortizationthe termination of transition regulatory assets. Increases in the deferral of regulatory assets in 2005 from 2004 resulted from higher shopping incentive deferrals ($119 million), partially offset by the RCP deferral of distribution costs and related interest ($15 million) and increased deferred interest onMISO costs ($1 million).
Increased income taxes in the shopping incentives ($5 million).first quarter of 2006 compared to the same period last year were primarily due to an increase in taxable income, partially offset by a reduction in the tax rates due to the continuing phase-out of the income-based Ohio franchise tax.
Other Income
OtherThe increase in other income decreased by $7of $14 million in the first quarter of 2005, compared with the first quarter of 2004,was primarily due to an increaseinterest income on associated company notes receivable from the generation asset transfers discussed above. Excluding the effects of the asset transfer, other income increased $6 million due to the absence in 2006 of $5 million in expenses related to the sales of customer receivables and a $2 million potential NRC fine related to the Davis-Besse Plant (see Outlook - Other Legal Proceedings).in the first quarter of 2005. The customer receivables sales expenses ceased in 2005 as result of the renewal of the CFC financing arrangement.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $2$1 million in the first quarter of 20052006 from the same quarter last year, reflecting the effects of redemptions and refinancings of $281 million and $46 million, respectively, subsequent to the first quarter of 2004.year.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements increaseddecreased by $1$3 million in the first quarter of 2005,2006, compared to the same period last year due to premiums related toas a result of the optional redemption of CEI's remaining outstanding preferred stock redemptions in the first quarter of 2005.
Capital Resources and Liquidity
CEI’sDuring 2006, CEI expects to meet its contractual obligations with cash requirements in 2005 for operating expenses, construction expenditures, scheduled debt maturitiesfrom operations and preferred stock redemptions are expected to be met without increasing net debt and preferred stock outstanding.short-term credit arrangements. Thereafter, CEI expects to use a combination of cash from operations and funds from the capital markets.
Changes in Cash Position
As of March 31, 2005,2006, CEI had $207,000$217,000 of cash and cash equivalents, compared with $197,000$207,000 as of December 31, 2004.2005. The major sources of changes in these balances are summarized below.
Cash Flows from Operating Activities
Cash provided byfrom operating activities during the first quarter of 2005,2006, compared with the first quarter of 2004,2005, were as follows:
| | | | Three Months Ended March 31, | | Operating Cash Flows | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | (in millions) | | | | | | | | | | | | | | Cash earnings(1) | | $ | 13 | | $ | 72 | | | $ | 31 | | $ | 13 | | | Working capital and other | | | 90 | | | 76 | | | | 94 | | | 90 | | Total | | $ | 103 | | $ | 148 | | | | Net cash provided from operating activities | | | $ | 125 | | $ | 103 | |
| (1) | Cash earnings is a non-GAAP measure (see reconciliation below). |
(1)Cash earnings are a non-GAAP measure (see reconciliation below).
Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. CEI believes that cash earnings isare a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.income: | | | Three Months Ended | | | Three Months Ended | | | | | March 31, | | | March 31, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | (In millions) | | | Net Income (GAAP) | | $ | 15 | | $ | 48 | | | $ | 72 | | $ | 15 | | | Non-Cash Charges (Credits): | | | | | | | | | | | | | | | | Provision for depreciation | | | 31 | | | 32 | | | | 17 | | | 31 | | | Amortization of regulatory assets | | | 54 | | | 48 | | | | 32 | | | 54 | | | Deferral of new regulatory assets | | | (25 | ) | | (18 | ) | | | (22 | ) | | (25 | ) | | Nuclear fuel and capital lease amortization | | | 4 | | | 5 | | | | - | | | 4 | | | Amortization of electric service obligation | | | (5 | ) | | (4 | ) | | | (4 | ) | | (5 | ) | | Deferred rents and lease market valuation liability | | | (53 | ) | | (42 | ) | | | (55 | ) | | (53 | ) | | Deferred income taxes and investment tax credits, net | | | (4 | ) | | (4 | ) | | | (1 | ) | | (4 | ) | | Accrued retirement benefit obligations | | | (1 | ) | | 6 | | | | Accrued compensation, net | | | (3 | ) | | 1 | | | Deferred purchased power costs | | | | (8 | ) | | - | | Accrued compensation and retirement benefits | | | | - | | | (4 | ) | Cash earnings (Non-GAAP) | | $ | 13 | | $ | 72 | | | $ | 31 | | $ | 13 | |
The $59 Net cash provided from operating activities increased by $22 million decreasein the first quarter of 2006 from the first quarter of 2005 as a result of an $18 million increase in cash earnings is described above and under "Results of Operations", partially offset by and a $14$4 million increase from working capital and other cash flows. The largest factors contributing to the change in working capital and other cash flows were changes in accrued taxes, accrued interest and accounts payable, partially offset by changes in receivables.
Cash Flows from Financing Activities
Net cash used for financing activities increased $19decreased $64 million in the first quarter of 20052006 from the first quarter of 2004.2005. The increasedecrease in funds used for financing activities primarily resulted from $98a $70 million of optional redemptions ofreduction in net preferred stock in the first quarter of 2005,and debt redemptions, partially offset by a reductionan $8 million increase in net debt redemptions.common stock dividend payments to FirstEnergy.
CEI had $207,000$29 million of cash and temporary investments (which included short-term notes receivable from associated companies) and approximately $471$304 million of short-term indebtedness as of March 31, 2005.2006. CEI has obtained authorization from the PUCO to incur short-term debt of up to $500 million (including through the available bank facility and the utility money pool described below). As of March 31, 2006, CEI had the capability to issue $1.4 billion$129 million of additional FMB 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 is permitted under the indenture to incur additional secured debt not otherwise permitted by a specified exception of up to $565$576 million as of March 31, 2005.2006. CEI has no restrictions on the issuance of preferred stock.
CFC is a wholly owned subsidiary of CEI whose borrowings are secured by customer accounts receivable purchased from CEI and TE. CFC can borrow up to $200 million under a receivables financing arrangement. As a separate legal entity with separate creditors, CFC would have to satisfy its obligations to creditors before any of its remaining assets could be made available to CEI. As of March 31, 2006, the facility was drawn for $94 million.
CEI has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 20052006 was 2.66%4.58%.
CEI, FirstEnergy, OE, Penn, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility through a syndicate of banks that expires in June 2010. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing and the commitment expiration date, as the same may be extended. CEI’s borrowing limit under the facility is $250 million subject to applicable regulatory approvals.
Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding LOC will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.
The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of March 31, 2006, CEI's debt to total capitalization as defined under the revolving credit facility was 52%.
The facility does not contain any provisions that either restrict CEI's ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to CEI's credit ratings.
CEI’s access to the capital markets and the costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook from the rating agenciesS&P on all such securities is stable.
On March 18, 2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affect FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the The ratings outlook would be revised tofrom Moody's and Fitch on all securities is positive.
On March 14, 2005,In April and May of 2006, pollution control notes that were formerly obligations of CEI were refinanced and became obligations of FGCO and NGC. The proceeds from the refinancings were used to repay a portion of their associated company notes payable to CEI. CEI redeemed all 500,000 outstanding shares$117.8 million of its Serial Preferred Stock, $7.40 Series A at a price of $101 per share plus accrued dividends to the date of the redemption. Also on March 14, 2005, CEI redeemed all 474,000 outstanding shares of its Serial Preferred Stock, Adjustable Rate Series L at a price of $100 per share plus accrued dividends to the date of the redemption.pollution control notes having variable interest rates.
On April 20, 2005, Beaver County Industrial Development Authority pollution control bonds aggregating $53.9 million were refunded. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance and secured by FMB.
On June 1, 2005, CEI intends to redeem all of its 40,000 outstanding shares of $7.35 Series C preferred stock at $101.00 per share, plus accrued dividends to the date of redemption.
Cash Flows from Investing Activities
Net cash used for investing activities was $4 million in the first quarter of 2006 compared to net cash provided from investing activities wasof $82 million in the first quarter of 2005 compared to cash used for investing activities of $7 million in the first quarter of 2004.2005. The change was primarily due to increased loan payments received fromloans to associated companies, partially offset by higher property additions.a reduction in investments in lessor notes.
During CEI’s capital spending for the remaininglast three quarters of 2005, capital requirements for property additions are2006 is expected to be about $85 million, including $1 million for nuclear fuel. CEI has additional requirements of approximately $1 million to meet sinking fund requirements for preferred stock during the remainder of 2005.million. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.
CEI’s capital spending for the period 2005-20072006-2010 is expected to be about $368$615 million (excluding nuclear fuel) of which approximately $108$122 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $75 million, of which about $10 million applies to 2005. During the same periods, CEI’s nuclear fuel investments are expected to be reduced by approximately $90 million and $27 million, respectively, as the nuclear fuel is consumed.2006.
Off-Balance Sheet Arrangements
Obligations not included on CEI’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant. As of March 31, 2005,2006, the present value of these operating lease commitments, net of trust investments, total $99$96 million.
CEI sells substantially all of its retail customer receivables to CFC, its wholly owned subsidiary. 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 $94 million of off-balance sheet financing as of March 31, 2005.
Equity Price Risk
Included in CEI’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $249 million and $242 million as of March 31, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $25 million reduction in fair value as of March 31, 2005.
Outlook
The electric industry continues to transition to a more competitive environment and all of CEI'sCEI’s customers can select alternative energy suppliers. CEI 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. CEI has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
Regulatory Matters
In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of CEI's customers elects to obtain power from an alternative supplier, CEI reduces the customer's bill with a "generation shopping credit," based on the generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. CEI has continuing PLR responsibility to its franchise customers through December 31, 2005.
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. FES acts as an alternate supplier for a portion of the load in CEI's franchise area.
CEI's revised Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, and continues CEI's support of energy efficiency and economic development efforts. Other key components of the revised Rate Stabilization Plan include the following:
· | extension of the amortization period for transition costs being recovered through the RTC from 2008 to as late as mid-2009; |
· | deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and |
· | ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes. |
On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may require CEI to undertake, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. Any acceptance of future competitive bid results would terminate the Rate Stabilization Plan pricing, but not the related approved accounting, and not until twelve months after the PUCO authorizes such termination.
On December 30, 2004, CEI filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $16 million in transmission and ancillary service costs beginning January 1, 2006. CEI also filed an application for authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ATSI rate increase, as applicable, from October 1, 2003 through December 31, 2005.
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, Ohio. Under the FERC's decision, CEI may be responsible for a portion of new energy market charges imposed by 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. On April 15, 2005, FERC issued an order on rehearing that "carves out" these contracts from the MISO Day 2 market. While the order on rehearing is favorable to CEI, the impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmission service and MISO's ability to administer the contracts. Accordingly, the impact of this decision cannot be determined at this time.
Regulatory assets are costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, withoutor for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income whenas incurred. CEI'sAll regulatory assets are expected to be recovered under the provisions of CEI’s transition plan. CEI’s regulatory assets as of March 31, 2006 and December 31, 2005, were $858 million and $862 million, respectively.
On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming that order with respect to the approval of the rate stabilization charge, approval of the shopping credits, the grant of interest on shopping credit incentive deferral amounts, and approval of FirstEnergy’s financial separation plan. It remanded the approval of the RSP pricing back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient customer participation in the competitive marketplace. Under provisions of the RSP, the PUCO had required the Ohio Companies to undertake a CBP to secure generation and allow for customer pricing participation in the competitive marketplace. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until 12 months after the PUCO authorizes such termination. On December 9, 2004, the PUCO rejected the auction price results from the CBP for the generation supply period beginning January 1, 2006 and issued an entry stating that the pricing under the approved revised RSP would take effect on January 1, 2006. On February 23, 2006 the CBP auction manager, National Economic Research Associates, notified the PUCO that a subsequent CBP to potentially provide firm generation service for the Ohio Companies' 2007 and 2008 actual load requirements could not proceed due to lack of interest, as there were no bidder applications submitted. Additionally, on March 20, 2006, the PUCO denied applications for rehearing filed by various parties regarding the PUCO's rules for the CBP. The above May 3, 2006 Supreme Court of Ohio opinion may require the PUCO to reconsider this customer pricing process.
On January 4, 2006, the PUCO approved, with modifications, CEI’s RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include: | · | Maintaining the existing level of base distribution rates through April 30, 2009 for CEI; | | | | | · | Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred by all of the Ohio Companies during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years; | | | | | · | Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2010 for CEI; | | | | | · | Reducing the deferred shopping incentive balances as of January 1, 2006 by up to $85 million for CEI by accelerating the application of its accumulated cost of removal regulatory liability; and | | | | | · | Deferring and capitalizing (for recovery over a 25-year period) increased fuel costs above the amount collected through the Ohio Companies’ fuel recovery mechanism (in lieu of implementation of the GCAF rider). |
The following table provides CEI’s estimated amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2006 through 2010:
Amortization | | | | Period | | Amortization | | | | | (In millions) | | | 2006 | | $ | 97 | | | 2007 | | | 113 | | | 2008 | | | 130 | | | 2009 | | | 211 | | | 2010 | | | 263 | | Total Amortization | | $ | 814 | |
The PUCO’s January 4, 2006 approval of the RCP also included approval of the Ohio Companies’ supplemental stipulation which was filed with the PUCO on November 4, 2005 and which was an additional component of the RCP filed on September 9, 2005. On January 10, 2006, the Ohio Companies filed a Motion for Clarification of the PUCO order approving the RCP. The Ohio Companies sought clarity on issues related to distribution deferrals, including requirements of the review process, timing for recognizing certain deferrals and definitions of the types of qualified expenditures. The Ohio Companies also sought confirmation that the list of deferrable distribution expenditures originally included in the revised stipulation fall within the PUCO order definition of qualified expenditures. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies’ requests to: | · | Recognize fuel and distribution deferrals commencing January 1, 2006; | | | | | · | Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff; |
| | | | · | Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and | | | | | · | Clarify that distribution expenditures do not have to be “accelerated” in order to be deferred. |
The PUCO approved the Ohio Companies’ methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies’ Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. The Ohio Companies responded to the applications for rehearing on February 13, 2006. In an Entry on Rehearing issued by the PUCO on March 1, 2006, all motions for rehearing were denied. Certain of these parties have subsequently filed their notices of appeal with the Supreme Court of Ohio alleging various errors made by the PUCO in its order approving the RCP.
On December 30, 2004, were $0.9 billionCEI filed with the PUCO two applications related to the recovery of transmission and $1.0 billion, respectively.ancillary service related costs. The first application sought recovery of these costs beginning January 1, 2006. CEI is deferring customer shopping incentives and interestrequested that these costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $320 million as of March 31, 2005 and will be recovered through a surcharge raterider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues expected to be recovered from January through June 30, 2006 are approximately $24 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. On May 1, 2006, CEI filed a modification to the rider to determine revenues from July 2006 through June 2007.
The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for CEI to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized CEI to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of CEI's case with a similar case involving Dayton Power & Light Company. Oral argument is currently scheduled for May 10, 2006.
On January 20, 2006 the OCC sought rehearing of the PUCO approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The OCC's brief is expected to be filed during the second quarter of 2006. The briefs of the PUCO and CEI will be due within thirty days of the OCC's filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On April 18, 2006, the Court denied both parts of the motion but on its own motion consolidated the OCC's appeal of CEI's case with a similar case of Dayton Power & Light Company and stayed briefing on these appeals.
On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies at a price equal to the RTC rateretail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio competitive bid process results in effect when the transition costs have been fully recovered. Recovery of the new regulatory assets will begina lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at that time and amortization of the regulatory assets for each accounting period will bea fixed price equal to the surcharge revenue recognizedretail generation price during that period.2006. The PPUC approved Penn's plan with modifications on April 20, 2006 to use an RFP process to obtain its power supply requirements after 2006.
On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticized the Ohio competitive bid process, and required FES to submit additional evidence in support of the reasonableness of the prices charged in the power sales agreements. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in late January 2007, as a result of the April 20, 2006 extension of the procedural schedule. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order and the FERC granted rehearing for future consideration on March 1, 2006.
See Note 1311 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.
Environmental Matters
CEI accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably determineestimate the amount of such costs. Unasserted claims are reflected in CEI'sCEI’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
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 March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 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. CAIR will require additional reductions of NOx and SO2 emissions in two phases (Phase I in 2009 for NOx, 2010 for SO2 and Phase II in 2015 for both NOx and SO2). CEI's Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO2 and NOx emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOx emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOx cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which CEI operates 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 March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline by 2010 as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. The future cost of compliance with these regulations may be substantial.
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 United States 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 percent through 2012.
CEI 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 KWH of electricity generated by CEI is lower than many regional competitors due to CEI's diversified generation sources which include low or non-CO2 emitting gas-fired and nuclear generators.
FirstEnergy plans to issue a report that will disclose the Companies’ environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by December 1, 2005 and will post the report on its web site,www.firstenergycorp.com.
Regulation of Hazardous Waste
CEI has been named 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 Sheet as of March 31, 2005,2006, based on estimates of the total costs of cleanup, CEI'sCEI’s proportionate responsibility for such costs and the financial ability of other nonaffiliatedunaffiliated entities to pay. Included in CurrentOther Noncurrent Liabilities are accrued liabilities aggregating approximately $2.3$1.7 million as of March 31, 2005.2006.
See Note 12(B)10(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.
Other Legal Proceedings
There are various lawsuits, claims (including claims for asbestos exposure)Power Outages and proceedings related to CEI's normal business operations pending against CEI and its subsidiaries. The most significant not otherwise discussed above are described below.Related Litigation-
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. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,concluded, 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 real-time 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 contained 46 "recommendations“recommendations to prevent or minimize the scope of future blackouts."” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in process,new or material upgrades to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother applicable government agencies and reliability coordinators may, however, 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 asFinally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of March 31, 2005 forcontrol room operators before determining the next steps, if any, expenditures in excess of those actually incurred through that date.the proceeding.
Three substantially similar actionsFirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in various Ohio State courts by plaintiffs seekingbut were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent customers whoothers as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of the four cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc. as well) for claims paid to insureds for damages allegedly suffered damagesarising as a result of the loss of power on August 14, 2003 power outages. All three2003. The listed insureds in these cases, werein many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. On March 7, 2006, the PUCO issued a ruling applicable to all pending cases. Among its various rulings, the PUCO consolidated all of the pending outage cases for hearing; limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence; and gave the plaintiffs additional time to amend their complaints to otherwise comply with the PUCO’s underlying order. The plaintiffs in one case have since filed an amended complaint. The named FirstEnergy companies have answered and also have filed a motion to dismiss the action, which is pending. Also, most complainants, along with the FirstEnergy companies, filed applications for lackrehearing with the PUCO over various rulings contained in the March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow the insurance company claimants, as insurers, to prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities which provide their service. The PUCO denied all other motions for rehearing. No estimate of jurisdiction. One case was refiled on January 12, 2004 at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. In the remaining case, the Courtpotential liability is available for any of Appeals on March 31, 2005 affirmed the trial court’s decision dismissing the case. It is not yet known whether further appeal will be sought.these cases. In addition to the one case that was refiled at the PUCO,these six cases, 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. Following the PUCO's March 7, 2006 order, that action was voluntarily dismissed by the claimants.
One complaint was filed on August 25, 2004 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 timetable for a decision on the motion to dismiss has been established by the Court. 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 initiated against the Companies. In particular,Although unable to predict the impact of these proceedings, 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'sFirstEnergy’s or its subsidiaries'subsidiaries’ financial condition, and results of operations.operations and cash flows.
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 Nuclear Power Station, in which CEI has a 51.38% interest. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse.Other Legal Matters-
On April 21, 2005, the NRC issued a NOVThere are various lawsuits, claims (including claims for asbestos exposure) and proposed a $5.45 million civil penaltyproceedings related to the degradation of the Davis-Besse reactor vessel headCEI’s normal business operations pending against CEI and its subsidiaries. The other potentially material items not otherwise discussed above are described above. Under the NRC’s letter, FENOC has ninety days to respond to this NOV. CEI has accrued the remaining liability for its share of the proposed fine of $1.8 million during the first quarter of 2005.
If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability based on the Davis-Besse head degradation, 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 notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. FENOC operates the Perry Nuclear Power Plant, in which CEI has a 44.85% interest. On April 4, 2005, the NRC held a public forum to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives although it remained under the heightened NRC oversight since August 2004. During the public forum and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.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 CEI,the Ohio Companies, and the Davis-Besse extended outage, have 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. On December 30, 2004, FirstEnergy received a second subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse related disclosures, which FirstEnergy has provided. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.
The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will decide this case.
If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, and results of operations.operations and cash flows.
See Note 12(C)10 (C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.
New Accounting Standards and Interpretations
FIN 47,“Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”
On March 30, 2005, the FASB issued this interpretation to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. FirstEnergy is currently evaluating the effect this standard will have on the financial statements.
EITF Issue No. 03-1, "The Meaning04-13, "Accounting for Purchases and Sales of Other-Than-Temporary Impairment and its Application to Certain Investments"Inventory with the Same Counterparty"
In March 2004,September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus on the application guidancethat an exchange of inventory should be accounted 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 valuevalue. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and the impairment loss recognizedother storable inventory. Therefore, CEI will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective forinterim or annual periods beginning after JuneMarch 15, 2004, were delayed by2006. This EITF issue will not have a material impact on CEI's financial results.
SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140”
In February 2006, the issuanceFASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of FSP EITF 03-1-1 in September 2004. DuringFinancial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the periodrequirements of delay, FirstEnergy will continueSFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. CEI is currently evaluating the impact of this Statement on its investments as required by existing authoritative guidance.financial statements.
THE TOLEDO EDISON COMPANY | THE TOLEDO EDISON COMPANY | | THE TOLEDO EDISON COMPANY | | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | (Unaudited) | | (Unaudited) | | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | | March 31, | | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | 2005 | | 2004 | | | March 31, | | | | | | | | | | | | 2006 | | 2005 | | STATEMENTS OF INCOME | | | | (In thousands) | | | (In thousands) | | | | | | | | | | | | | | | | OPERATING REVENUES | | | | | $ | 241,755 | | $ | 235,398 | | | $ | 217,977 | | $ | 241,755 | | | | | | | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | | | Fuel | | | | | 12,569 | | 10,214 | | | | 9,762 | | | 12,569 | | | Purchased power | | | | | 80,156 | | 82,408 | | | | 72,418 | | | 80,156 | | | Nuclear operating costs | | | | | 59,163 | | 42,692 | | | | 17,332 | | | 59,163 | | | Other operating costs | | | | | 34,348 | | 36,208 | | | | 40,425 | | | 34,348 | | | Provision for depreciation | | | | | 14,680 | | 14,053 | | | | 8,097 | | | 14,680 | | | Amortization of regulatory assets | | | | | 34,865 | | 33,666 | | | | 24,456 | | | 34,865 | | | Deferral of new regulatory assets | | | | | (9,424 | ) | | (7,030 | ) | | | (10,654 | ) | | (9,424 | ) | | General taxes | | | | | 14,181 | | 14,300 | | | | 12,931 | | | 14,181 | | | Income tax benefit | | | | | | (3,968 | ) | | (1,578 | ) | | | Income taxes (benefit) | | | | 14,418 | | | (3,968 | ) | | Total operating expenses and taxes | | | | | | 236,570 | | | 224,933 | | | | 189,185 | | | 236,570 | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | | | 5,185 | | 10,465 | | | | 28,792 | | | 5,185 | | | | | | | | | | | | | | | | | | | OTHER INCOME (net of income taxes) | | | | | 2,659 | | 5,833 | | | | 4,310 | | | 2,659 | | | | | | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | | | | | | Interest on long-term debt | | | | | 4,220 | | 9,461 | | | | 2,790 | | | 4,220 | | | Allowance for borrowed funds used during construction | | | | | 443 | | (1,400 | ) | | | (214 | ) | | 443 | | | Other interest expense | | | | | | 2,816 | | | 706 | | | | 1,520 | | | 2,816 | | | Net interest charges | | | | | 7,479 | | 8,767 | | | | 4,096 | | | 7,479 | | | | | | | | | | | | | | | | | | | NET INCOME | | | | | 365 | | 7,531 | | | | 29,006 | | | 365 | | | | | | | | | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | | | | 2,211 | | | 2,211 | | | | 1,275 | | | 2,211 | | | | | | | | | | | | | | | | | | | EARNINGS (LOSS) APPLICABLE TO COMMON STOCK | | | | | $ | (1,846 | ) | $ | 5,320 | | | $ | 27,731 | | $ | (1,846 | ) | | | | | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | | | | 365 | | 7,531 | | | $ | 29,006 | | $ | 365 | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | Unrealized gain (loss) on available for sale securities | | | | | (1,683 | ) | | 5,682 | | | | Income tax related to other comprehensive income | | | | | | 695 | | | (2,331 | ) | | | Other comprehensive income (loss), net of tax | | | | | | (988 | ) | | 3,351 | | | | Unrealized loss on available for sale securities | | | | (1,138 | ) | | (1,683 | ) | | Income tax benefit related to other comprehensive income | | | | 411 | | | 695 | | | Other comprehensive loss, net of tax | | | | (727 | ) | | (988 | ) | | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME (LOSS) | | | | | $ | (623 | ) | $ | 10,882 | | | $ | 28,279 | | $ | (623 | ) | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral partof these statements. | The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral partof these statements. | | | | | | | | | | | | | | | | | | | | | | | | |
THE TOLEDO EDISON COMPANY | | | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | | | March 31, | | December 31, | | | | | | | 2005 | | 2004 | | | | | | | (In thousands) | | ASSETS | | | | | | | | UTILITY PLANT: | | | | | | | | | In service | | | | | $ | 1,857,720 | | $ | 1,856,478 | | | Less - Accumulated provision for depreciation | | | | | | 789,915 | | | 778,864 | | | | | | | | | 1,067,805 | | | 1,077,614 | | | Construction work in progress- | | | | | | | | | | | | Electric plant | | | | | | 66,405 | | | 58,535 | | | Nuclear fuel | | | | | | 22,634 | | | 15,998 | | | | | | | | | 89,039 | | | 74,533 | | | | | | | | | 1,156,844 | | | 1,152,147 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | Investment in lessor notes | | | | | | 178,764 | | | 190,692 | | | Nuclear plant decommissioning trusts | | | | | | 305,046 | | | 297,803 | | | Long-term notes receivable from associated companies | | | | | | 40,002 | | | 39,975 | | | Other | | | | | | 1,835 | | | 2,031 | | | | | | | | | 525,647 | | | 530,501 | | CURRENT ASSETS: | | | | | | | | | | | | Cash and cash equivalents | | | | | | 15 | | | 15 | | | Receivables- | | | | | | | | | | | | Customers | | | | | | 6,443 | | | 4,858 | | | Associated companies | | | | | | 12,180 | | | 36,570 | | | Other | | | | | | 4,138 | | | 3,842 | | | Notes receivable from associated companies | | | | | | 137,266 | | | 135,683 | | | Materials and supplies, at average cost | | | | | | 46,769 | | | 40,280 | | | Prepayments and other | | | | | | 1,206 | | | 1,150 | | | | | | | | | 208,017 | | | 222,398 | | DEFERRED CHARGES: | | | | | | | | | | | | Goodwill | | | | | | 504,522 | | | 504,522 | | | Regulatory assets | | | | | | 349,297 | | | 374,814 | | | Property taxes | | | | | | 24,100 | | | 24,100 | | | Other | | | | | | 43,312 | | | 25,424 | | | | | | | | | 921,231 | | | 928,860 | | | | | | | | $ | 2,811,739 | | $ | 2,833,906 | | CAPITALIZATION AND LIABILITIES | | | | | | | | | | | CAPITALIZATION: | | | | | | | | | | | | Common stockholder's equity- | | | | | | | | | | | | Common stock, $5 par value, authorized 60,000,000 shares - | | | | | | | | | | | | 39,133,887 shares outstanding | | | | | $ | 195,670 | | $ | 195,670 | | | Other paid-in capital | | | | | | 428,559 | | | 428,559 | | | Accumulated other comprehensive income | | | | | | 19,051 | | | 20,039 | | | Retained earnings | | | | | | 189,213 | | | 191,059 | | | Total common stockholder's equity | | | | | | 832,493 | | | 835,327 | | | Preferred stock | | | | | | 126,000 | | | 126,000 | | | Long-term debt | | | | | | 300,131 | | | 300,299 | | | | | | | | | 1,258,624 | | | 1,261,626 | | CURRENT LIABILITIES: | | | | | | | | | | | | Currently payable long-term debt | | | | | | 90,950 | | | 90,950 | | | Accounts payable- | | | | | | | | | | | | Associated companies | | | | | | 116,930 | | | 110,047 | | | Other | | | | | | 2,299 | | | 2,247 | | | Notes payable to associated companies | | | | | | 394,761 | | | 429,517 | | | Accrued taxes | | | | | | 31,695 | | | 46,957 | | | Lease market valuation liability | | | | | | 24,600 | | | 24,600 | | | Other | | | | | | 80,005 | | | 53,055 | | | | | | | | | 741,240 | | | 757,373 | | NONCURRENT LIABILITIES: | | | | | | | | | | | | Accumulated deferred income taxes | | | | | | 221,759 | | | 221,950 | | | Accumulated deferred investment tax credits | | | | | | 24,562 | | | 25,102 | | | Retirement benefits | | | | | | 39,838 | | | 39,227 | | | Asset retirement obligation | | | | | | 197,564 | | | 194,315 | | | Lease market valuation liability | | | | | | 261,850 | | | 268,000 | | | Other | | | | | | 66,302 | | | 66,313 | | | | | | | | | 811,875 | | | 814,907 | | COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | | | | | | | | $ | 2,811,739 | | $ | 2,833,906 | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these balance sheets. | | | | | | | | | | | | |
THE TOLEDO EDISON COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | March 31, | | December 31, | | | | | 2006 | | 2005 | | | | | (In thousands) | | ASSETS | | | | | | UTILITY PLANT: | | | | | | | In service | | $ | 834,124 | | $ | 824,677 | | | Less - Accumulated provision for depreciation | | | 377,586 | | | 372,845 | | | | | | 456,538 | | | 451,832 | | | Construction work in progress | | | 36,277 | | | 33,920 | | | | | | 492,815 | | | 485,752 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Investment in lessor notes | | | 169,463 | | | 178,798 | | | Nuclear plant decommissioning trusts | | | 58,458 | | | 59,209 | | | Long-term notes receivable from associated companies | | | 436,446 | | | 436,178 | | | Other | | | 1,770 | | | 1,781 | | | | | | 666,137 | | | 675,966 | | CURRENT ASSETS: | | | | | | | | | Cash and cash equivalents | | | 15 | | | 15 | | | Receivables- | | | | | | | | | Customers | | | 751 | | | 2,209 | | | Associated companies | | | 28,275 | | | 16,311 | | | Other | | | 4,697 | | | 6,410 | | | Notes receivable from associated companies | | | 59,681 | | | 48,349 | | | Prepayments and other | | | 693 | | | 1,059 | | | | | | 94,112 | | | 74,353 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 500,576 | | | 501,022 | | | Regulatory assets | | | 275,671 | | | 287,095 | | | Prepaid pension costs | | | 35,345 | | | 35,566 | | | Property taxes | | | 18,047 | | | 18,047 | | | Other | | | 40,988 | | | 24,164 | | | | | | 870,627 | | | 865,894 | | | | | $ | 2,123,691 | | $ | 2,101,965 | | CAPITALIZATION AND LIABILITIES | | | | | | | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity - | | | | | | | | | Common stock, $5 par value, authorized 60,000,000 shares - | | | | | | | | | 39,133,887 shares outstanding | | $ | 195,670 | | $ | 195,670 | | | Other paid-in capital | | | 473,894 | | | 473,638 | | | Accumulated other comprehensive income | | | 3,963 | | | 4,690 | | | Retained earnings | | | 192,159 | | | 189,428 | | | Total common stockholder's equity | | | 865,686 | | | 863,426 | | | Preferred stock | | | 66,000 | | | 96,000 | | | Long-term debt | | | 237,722 | | | 237,753 | | | | | | 1,169,408 | | | 1,197,179 | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | | 53,650 | | | 53,650 | | | Accounts payable- | | | | | | | | | Associated companies | | | 30,004 | | | 46,386 | | | Other | | | 3,085 | | | 2,672 | | | Notes payable to associated companies | | | 120,228 | | | 64,689 | | | Accrued taxes | | | 69,745 | | | 49,344 | | | Lease market valuation liability | | | 24,600 | | | 24,600 | | | Other | | | 43,281 | | | 40,049 | | | | | | 344,593 | | | 281,390 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 213,298 | | | 221,149 | | | Accumulated deferred investment tax credits | | | 11,622 | | | 11,824 | | | Lease market valuation liability | | | 237,250 | | | 243,400 | | | Retirement benefits | | | 41,242 | | | 40,353 | | | Asset retirement obligation | | | 25,252 | | | 24,836 | | | Deferred revenues - electric service programs | | | 30,374 | | | 32,606 | | | Other | | | 50,652 | | | 49,228 | | | | | | 609,690 | | | 623,396 | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | $ | 2,123,691 | | $ | 2,101,965 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of | | | | | these balance sheets. | | | | | | | |
THE TOLEDO EDISON COMPANY | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | March 31, | | | | | | | | | | | | | | | | 2005 | | 2004 | | | | | | | | | | | | | | | | (In thousands) | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | Net income | | | | | $ | 365 | | $ | 7,531 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | | | Provision for depreciation | | | | | | 14,680 | | | 14,053 | | | Amortization of regulatory assets | | | | | | 34,865 | | | 33,666 | | | Deferral of new regulatory assets | | | | | | (9,424 | ) | | (7,030 | ) | | Nuclear fuel and capital lease amortization | | | | | | 4,868 | | | 5,506 | | | Deferred rents and lease market valuation liability | | | | | | (15,224 | ) | | (7,692 | ) | | Deferred income taxes and investment tax credits, net | | | | | | (1,387 | ) | | (2,031 | ) | | Accrued retirement benefit obligations | | | | | | 611 | | | 2,285 | | | Accrued compensation, net | | | | | | (1,265 | ) | | (733 | ) | | Decrease (Increase) in operating assets: | | | | | | | | | | | | Receivables | | | | | | 41,475 | | | 20,035 | | | Materials and supplies | | | | | | (6,489 | ) | | (1,434 | ) | | Prepayments and other current assets | | | | | | (56 | ) | | 3,384 | | | Increase (Decrease) in operating liabilities: | | | | | | | | | | | | Accounts payable | | | | | | 6,935 | | | (6,074 | ) | | Accrued taxes | | | | | | (15,262 | ) | | (14,085 | ) | | Accrued interest | | | | | | 853 | | | (2,280 | ) | | Other | | | | | | (1,989 | ) | | (8,147 | ) | | Net cash provided from operating activities | | | | | | 53,556 | | | 36,954 | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | New Financing- | | | | | | | | | | | | Long-term debt | | | | | | -- | | | 73,000 | | | Redemptions and Repayments- | | | | | | | | | | | | Long-term debt | | | | | | -- | | | (15,000 | ) | | Short-term borrowings, net | | | | | | (34,993 | ) | | (93,299 | ) | | Dividend Payments- | | | | | | | | | | | | Preferred stock | | | | | | (2,211 | ) | | (2,211 | ) | | Net cash used for financing activities | | | | | | (37,204 | ) | | (37,510 | ) | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | Property additions | | | | | | (17,919 | ) | | (8,440 | ) | | Loan repayments from (loans to) associated companies, net | | | | | | (1,610 | ) | | 2,606 | | | Investments in lessor notes | | | | | | 11,928 | | | 10,280 | | | Contributions to nuclear decommissioning trusts | | | | | | (7,135 | ) | | (7,135 | ) | | Other | | | | | | (1,616 | ) | | 1,024 | | | Net cash used for investing activities | | | | | | (16,352 | ) | | (1,665 | ) | | | | | | | | | | | | | | Net change in cash and cash equivalents | | | | | | -- | | | (2,221 | ) | | Cash and cash equivalents at beginning of period | | | | | | 15 | | | 2,237 | | | Cash and cash equivalents at end of period | | | | | $ | 15 | | $ | 16 | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integralpart of these statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
THE TOLEDO EDISON COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | Three Months Ended | | | | | March 31, | | | | | 2006 | | 2005 | | | | | (In thousands) | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 29,006 | | $ | 365 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | Provision for depreciation | | | 8,097 | | | 14,680 | | | Amortization of regulatory assets | | | 24,456 | | | 34,865 | | | Deferral of new regulatory assets | | | (10,654 | ) | | (9,424 | ) | | Nuclear fuel and capital lease amortization | | | - | | | 4,868 | | | Deferred rents and lease market valuation liability | | | (16,084 | ) | | (15,224 | ) | | Deferred income taxes and investment tax credits, net | | | (8,453 | ) | | (1,387 | ) | | Deferred purchased power costs | | | (3,002 | ) | | - | | | Accrued compensation and retirement benefits | | | 1,110 | | | (654 | ) | | Decrease (increase) in operating assets- | | | | | | | | | Receivables | | | (8,793 | ) | | 41,475 | | | Materials and supplies | | | - | | | (6,489 | ) | | Prepayments and other current assets | | | 366 | | | (56 | ) | | Increase (decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | (15,969 | ) | | 6,935 | | | Accrued taxes | | | 20,401 | | | (15,262 | ) | | Accrued interest | | | (668 | ) | | 853 | | | Electric service prepayment programs | | | (2,231 | ) | | - | | | Other | | | (121 | ) | | (1,989 | ) | | Net cash provided from operating activities | | | 17,461 | | | 53,556 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Short-term borrowings, net | | | 55,539 | | | - | | | Redemptions and Repayments- | | | | | | | | | Preferred stock | | | (30,000 | ) | | - | | | Short-term borrowings, net | | | - | | | (34,993 | ) | | Dividend Payments- | | | | | | | | | Common stock | | | (25,000 | ) | | - | | | Preferred stock | | | (1,275 | ) | | (2,211 | ) | | Net cash used for financing activities | | | (736 | ) | | (37,204 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (15,044 | ) | | (17,919 | ) | | Loans to associated companies | | | (11,270 | ) | | (1,610 | ) | | Investments in lessor notes | | | 9,335 | | | 11,928 | | | Proceeds from nuclear decommissioning trust fund sales | | | 13,793 | | | 106,009 | | | Investments in nuclear decommissioning trust funds | | | (13,793 | ) | | (113,144 | ) | | Other | | | 254 | | | (1,616 | ) | | Net cash used for investing activities | | | (16,725 | ) | | (16,352 | ) | | | | | | | | | | | Net change in cash and cash equivalents | | | - | | | - | | | Cash and cash equivalents at beginning of period | | | 15 | | | 15 | | | Cash and cash equivalents at end of period | | $ | 15 | | $ | 15 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral | | | | | part of these statements. | | | | | | | | | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the StockholdersStockholder and Board of Directors of The Toledo Edison Company:
We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of March 31, 2005,2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 20052006 and 2004.2005. 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 as of December 31, 2004,2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004;(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(G) and Note 11 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 March 7, 2005,February 27, 2006, we expressed an unqualified opinions thereon. Theopinion on those consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein.statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004,2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP Cleveland, Ohio May 3, 20058, 2006
THE TOLEDO EDISON COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain 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. TE’s power supply requirements are provided by FES - an affiliated company.
FirstEnergy Intra-System Generation Asset Transfers
On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred did not include TE's leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.
On October 24, 2005, TE completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.
On December 16, 2005, TE completed the intra-system transfer of its ownership interests in the nuclear generation assets to NGC through a sale at net book value. FENOC continues to operate and maintain the nuclear generation assets.
These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.
The transfers will affect TE’s near-term results with reductions in both revenues and expenses. Revenues are reduced due to the termination of certain arrangements with FES, under which TE previously sold its nuclear-generated KWH to FES and leased its non-nuclear generation assets to FGCO, a subsidiary of FES. TE’s expenses are lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets. With respect to TE's retained leashold interests in the Bruce Mansfield Plant and Beaver Valley Unit 2, TE has continued the generation KWH sales arrangement with FES and continues to be obligated on the applicable portion of expenses related to those interests. In addition, TE receives interest income on associated company notes receivable from the transfer of its generation net assets. FES will continue to provide TE’s PLR requirements under revised purchased power arrangements for the three-year period beginning January 1, 2006 (see Outlook - Regulatory Matters).
The effects on TE’s results of operations in the first quarter of 2006 compared to the first quarter of 2005 from the generation asset transfers are summarized in the following table:
| First Quarter 2006 vs First Quarter 2005 Income Statement Effects | Increase (Decrease) | | (In millions) | | | Operating Revenues: | | | | Non-nuclear generating units rent | | $ | (4 | ) (a) | Nuclear generated KWH sales | | | (22 | ) (b) | Total - Operating Revenues Effect | | | (26 | ) | | Operating Expenses and Taxes: | | | | | Fuel costs - nuclear | | | (4 | ) (c) | Nuclear operating costs | | | (39 | ) (c) | Provision for depreciation | | | (8 | ) (d) | General taxes | | | (1 | ) (e) | Income taxes | | | 11 | (i) | Total- Operating Expenses and Taxes Effect | | | (41 | ) | | Operating Income Effect | | | 15 | | | Other Income: | | | | | Interest income from notes receivable | | | 4 | (f) | Nuclear decommissioning trust earnings | | | (1 | ) (g) | Income taxes | | | (1 | ) (i) | Total-Other Income Effect | | | 2 | | | Net interest Charges: | | | | | Allowance for funds used during construction | | | 1 | | Total-Net Interest Charges Effect | | | (1 | ) (h) | | Net Income Effect | | $ | 18 | | | | | | | | (a) Elimination of non-nuclear generation assets lease to FGCO. | | (b) Reduction of nuclear generated wholesale KWH sales to FES. | | (c) Reduction of nuclear fuel and operating costs. | (d) Reduction of depreciation expense and asset retirement obligation accretion related to generation assets. | | (e) Reduction of property tax expense on generation assets. | | (f) Interest income on associated company notes receivable from the transfer of | | generation net assets. | | (g) Reduction of earnings on nuclear decommissioning trusts. | | (h) Absence in 2006 of adjustment to 2005 allowance for borrowed funds used during construction on generation assets transferred. | | (i) Income tax effect of the above adjustments. |
Results of Operations
Earnings applicable to common stock in the first quarter of 2005 decreased2006 increased to $28 million from a loss of $2 million from earnings of $5 million in the first quarter of 2004.2005. This decreaseincrease resulted primarily from higher nuclearreduced operating costs,expenses and taxes, reduced net interest charges and increased other income, which was partially offset by higherlower operating revenues and lower financing costs.revenues. These changes were principally from the effects of the generation asset transfer shown in the table above.
Operating Revenues
Operating revenues increaseddecreased by $6$24 million or 2.7%9.8% in the first quarter of 2005 from2006 compared with the same period of 2004. Higher2005, primarily due to the generation asset transfer impact shown in the table above. Excluding the asset transfer effects, operating revenues resulted principally from increased $2 million due to a $27 million increase in retail generation sales revenues of $10and a $6 million (industrialreduction in customer shopping incentives, partially offset by a $27 million decrease in distribution revenues and a $4 million decrease in wholesale sales to non-affiliates.
Retail generation revenues increased $27 million with increases in all customer classes (residential - $16 million, commercial - $9 million and commercialindustrial - - $1$2 million) and wholesale sales (primarily to FES) of $4 million, partially offset by a $7 million decrease in distribution revenues.
The industrial generation revenue increase was primarily due to higher unit prices and a 1.6%increased KWH sales increase.sales. The higher unit prices reflected the rate stabilization charge and fuel cost recovery rider that became effective in January 2006 under the RCP. The increase in commercial sector revenues was principally due to a 6.1%generation KWH sales increase. Residential retail generation revenues were nearly unchanged for(residential - 37.6%, commercial - 11.7% and industrial - 0.5%) primarily resulted from decreased customer shopping. The decreased shopping resulted from alternative energy suppliers terminating their supply arrangements with TE's shopping customers in the first quarter of 2005 as compared to last year due to higher unit prices offsetting the effect of a 4.5% KWH sales decrease. The increased commercial volume sales partially reflected the effect of lower customer shopping.2006. Generation services provided to commercial customers by alternative suppliers as a percent of total commercial sales deliveries in TE's franchise area decreased in all customer classes by nearly onethe following percentage point.points: residential - 24.3%, commercial - 8.5% and industrial - 1.4%.
The level of shopping in the industrial sector was relatively unchanged. The residential sales decrease resulted from an increase in residential shopping of 1.7 percentage points. Higherlower non-affiliated wholesale revenues reflected a decrease in sales to municipal customers ($1 million) and a $3 million decrease due to the effectcessation of increased nuclear generation available for salethe MSG sales arrangements under TE’s transition plan in December 2005. TE had been required to FES.provide the MSG to non-affiliated alternative suppliers.
Revenues from distribution throughput decreased by $7$27 million in the first quarter of 20052006 from the corresponding quarter of 2004.2005. The decrease was due toin all customer sectors (residential - $12 million; commercial - $13 million; and industrial - $1 million) primarily reflected lower industrialunit prices and residential revenues ($7 million and $1 million), principally due todecreased KWH deliveries. The lower composite unit prices. The impactprices reflected the completion of lower residential KWH sales contributed to the decrease while higher industrial sales partially offset the lower industrial sector unit prices. These revenue decreases weregeneration-related transition cost recovery under TE’s transition plan in 2005, partially offset by a $1 millionthe recovery of MISO costs beginning in 2006 (see Outlook - Regulatory Matters). The lower KWH distribution deliveries to residential and commercial revenue increase that resulted from a 4.2% sales volume increase partially offset by lower composite unit prices.customers reflected the impact of milder weather in the first quarter of 2006 compared to the same period of 2005.
Under the Ohio transition plan, TE provideshad provided incentives to customers to encourage switching to alternative energy providers. TE’s revenues were reduced by $0.5 million for additional credits in the first quarter of 2005, compared with the same period of 2004.providers, reducing TE's revenues. These revenue reductions, arewhich were deferred for future recovery under TE’s transition plan and dodid not affect current period earnings, ceased in 2006 and resulted in a $6 million change in revenues as discussed above. The deferred shopping incentives (Extended RTC) are currently being recovered under the RCP (see Outlook - Regulatory Matters below)Matters).
Changes in electric generation sales and distribution deliveries in the first quarter of 20052006 from the first quarter of 2004,2005 are summarized in the following table:
Changes in KWH Sales | | | | Increase (Decrease) | | | | | Electric Generation: | | | | Retail | | | 1.29.7 | % | Wholesale Wholesale: | | | 18.5 | | Non-Associated Companies | | | (40.3 | )% | Associated Companies(1) | | | (57.7 | )% | Total Electric Generation Sales | | | 9.2
(23.1 | )% | | Distribution Deliveries: | | | | | Residential | | | (1.71.3 | )% | Commercial | | | 4.2(3.8 | )% | Industrial | | | 2.0(0.9 | )% | Total Distribution Deliveries | | | 1.7
(2.0 | )% |
(1)Change reflects impact of generation asset transfers.
Operating Expenses and Taxes
Total operating expenses and taxes increaseddecreased by $12$47 million in the first quarter of 20052006 from the same quarter of 2004. The2005 principally due to the generation asset transfer effects as shown in the table above. Excluding the asset transfer effects, the following table presents changes from the prior year by expense category.category:
Operating Expenses and Taxes - Changes | | | | | | | Increase (Decrease) | | (In millions) | | | (In millions) | | | | | | | | | Fuel costs | | $ | 2 | | | | Purchased power costs | | | (2 | ) | | $ | (8 | ) | | Nuclear operating costs | | | 17 | | | | (2 | ) | | Other operating costs | | | (2 | ) | | | 6 | | | Provision for depreciation | | | 1 | | | | 2 | | | Amortization of regulatory assets | | | 1 | | | | (10 | ) | | Deferral of new regulatory assets | | | (2 | ) | | | (1 | ) | | Income taxes | | | (3 | ) | | | 7 | | Net increase in operating expenses and taxes | | $ | 12 | | | Total operating expenses and taxes | | | $ | (6 | ) |
Higher fuel costs in the first three months of 2005, compared with the same period of 2004, resulted principally from increased fossil and nuclear generation — up 28.1% and 29.8%, respectively. Lower purchased power costs reflect lower KWH purchased, partially offset by increased unit costs. Increased nuclear operating costs in the first quarter of 20052006 compared to the first quarter of 20042005 reflected lower unit prices associated with the new power supply agreement with FES and the RCP fuel cost deferrals of $3 million that began in 2006, partially offset by an increase in KWH purchased to meet the higher retail generation sales requirements. Decreased nuclear operating costs in the 2006 period were due to a refueling outage (including an unplanned extension) at the Perry nuclear plant and a mid-cycle inspection outage at the Davis-Besse nuclear plantlower costs associated with TE’s leasehold interest in theBeaver Valley Unit 2. The first quarter of 2005 and no scheduled outages inincluded costs related to preparations for the first quarter of 2004. Otherrefueling outage which began April 4, 2005. Higher other operating costs decreased due in partreflect increased transmission expenses, primarily related to lower employee benefit costs.MISO Day 2 operations that began on April 1, 2005.
Depreciation Excluding the effects of the generation asset transfers, depreciation charges increased by $1 million in the first three months of 2005 compared to the same period of 2004 due to an increase in depreciable property,distribution plant additions.
Lower amortization of regulatory assets reflected the completion of generation-related transition cost recovery under TE’s transition plan, partially offset by the effect of revised service life assumptions for fossil generating plants. Higher amortization of regulatory assets reflectsdeferred MISO costs that are being recovered in 2006. As discussed above, the increasedRCP transition costs amortization includes the amortization of transition costs. Increasesthe deferred shopping incentives, which began in 2006. The net change in deferrals of new regulatory assets primarily resulted from higherthe deferral of distribution costs and related interest ($6.1 million) under the RCP and deferrals of the 2006 MISO transmission costs and related interest ($1.7 million), partially offset by the termination of shopping incentivesincentive deferrals and interest ($0.56.4 million) and deferred interest onin 2006.
Increased income taxes in the shopping incentives ($1.5 million).first quarter of 2006 were primarily due to an increase in taxable income partially offset by a reduction in the tax rates due to the continuing phase-out of the income-based Ohio franchise tax.
Other Income
Other income decreased by $3increased $1.7 million in the first quarter of 2005,2006, compared to the same period of 2004, due to a2005. Excluding the effects of the generation asset transfer, other income decreased $0.3 million. The decrease reflected the absence in 2006 of $2.4 million of interest income earned on nuclear decommissioning trust investments andfrom a 2001 FGCO note (which had a balloon repayment in May 2005) partially offset by the accrual of a $1.6 million proposed NRC fine related to the Davis-Besse Plant (see Outlook - Other Legal Proceedings).in the first quarter of 2005.
Net Interest Charges
Net Excluding the effects of the asset transfer, net interest charges continued to trend lower, decreasing by $1$3 million in the first three monthsquarter of 20052006 from the same period of 2004,2005, reflecting redemptions and refinancing subsequent to the end of the first quarter of 2004.2005.
Capital Resources and Liquidity
TE’s cash requirements in 2005 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met without increasingits net debt and preferred stock outstanding. Thereafter, During 2006, TE expects to meet its contractual obligations with a combination of cash from operations and funds from theshort-term credit arrangements. In connection with a plan to realign its capital markets.structure, TE may issue up to $100 million of new long-term debt in 2006 with proceeds expected to fund a return of equity capital to FirstEnergy.
Changes in Cash Position
There was no change as of March 31, 20052006 from December 31, 20042005 in TE's cash and cash equivalents of $15,000.
Cash Flows From Operating Activities
Cash provided from operating activities during the first quarter of 2005,2006, compared with the first quarter of 20042005 were as follows:
| | | Three Months Ended March 31, | | | Three Months Ended March 31, | | Operating Cash Flows | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (in millions) | | | (In millions) | | | | | | | | | | Cash earnings(1) | | $ | 28 | | $ | 46 | | | $ | 21 | | $ | 28 | | | Working capital and other | | | 26 | | | (9 | ) | | | (3 | ) | | 26 | | | Total Cash Flows from Operating Activities | | $ | 54 | | $ | 37 | | | | Net cash provided from operating activities | | | $ | 18 | | $ | 54 | |
(1) Cash earnings is a non-GAAP measure (see reconciliation below).
Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP.TEGAAP. TE believes that cash earnings isare a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.income:
| | | Three Months Ended March 31, | | | Three Months Ended March 31, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (in millions) | | | | | | | | | | | (In millions) | | | Net Income (GAAP) | | $ | -- | | $ | 8 | | | $ | 29 | | $ | - | | | Non-Cash Charges (Credits): | | | | | | | | | | | | | | | | Provision for depreciation | | | 15 | | | 14 | | | | 8 | | | 15 | | | Amortization of regulatory assets | | | 35 | | | 34 | | | | 24 | | | 35 | | | Deferral of new regulatory assets | | | | (11 | ) | | (9 | ) | | Nuclear fuel and capital lease amortization | | | 5 | | | 6 | | | | - | | | 5 | | | Deferral of new regulatory assets | | | (9 | ) | | (7 | ) | | | Deferred operating lease costs, net | | | (15 | ) | | (8 | ) | | | Accrued retirement benefits obligation | | | 1 | | | 2 | | | | Accrued compensation | | | (2 | ) | | (1 | ) | | | Amortization of electric service obligation | | | | (2 | ) | | - | | | Deferred rents and lease market valuation liability | | | | (16 | ) | | (15 | ) | | Deferred income taxes and investment tax credits, net | | | (2 | ) | | (2 | ) | | | (8 | ) | | (2 | ) | | Deferred purchased power costs | | | | (3 | ) | | - | | | Accrued compensation and retirement benefits | | | | - | | | (1 | ) | | Cash earnings (Non-GAAP) | | $ | 28 | | $ | 46 | | | $ | 21 | | $ | 28 | |
Net cash provided from operating activities increaseddecreased by $17$36 million in the first quarter of 20052006 from the first quarter of 20042005 as a result of a $35 million increase in working capital partially offset by a $18$7 million decrease in cash earnings described above under “Results of Operations” and under "Results of Operations".a $29 million decrease from working capital. The change in working capital was primarily due to a $50 million decrease in cash provided from the settlement of receivables and $23 million of increased outflows for accounts payable, partially offset by changes in receivables and accounts payable.accrued taxes of $36 million.
Cash Flows From Financing Activities
Net cash used for financing activities decreased by $306,000$36 million in the first quarter of 2005,2006, as compared to the same period of 2004, reflecting2005. The decrease resulted from a change$91 million increase in net debt redemptions.short-term borrowings, partially offset by $30 million of preferred stock redemptions and $25 million of common stock dividends to FirstEnergy in 2006.
On January 20, 2006, TE redeemed all 1.2 million of its outstanding shares of Adjustable Preferred Rate Series B preferred stock at $25.00 per share, plus accrued dividends to the date of redemption.
TE had $137$60 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $395$120 million of short-term indebtedness as of March 31, 2005.2006. TE has authorization from the PUCO to incur short-term debt of up to $500 million (including through the available bank facility and the utility money pool described below). As of March 31, 2005,2006, TE had the capability to issue $907$628 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 $475 million$1.5 billion of preferred stock (assuming no additional debtdebt) was issued as of March 31, 2005)2006.
TE, FirstEnergy, OE, Penn, CEI, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility with a syndicate of banks that expires in June 2010. Borrowings under the facility are available to each Borrower separately and will mature on the earlier of 364 days from the date of borrowing and the commitment expiration date, as the same may be extended. TE’s borrowing limit under the facility is $250 million subject to applicable regulatory approval.
Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding letters of credit will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.
The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of March 31, 2006, TE's debt to total capitalization, as defined under the revolving credit facility, was 31%.
The facility does not contain any provisions that either restrict TE's ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to TE's credit ratings.
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, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 20052006 was 2.66%4.58%.
TE’s access to the capital markets and the costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook from S&P on all securities is stable. On March 18, 2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affect FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the The ratings outlook would be revised tofrom Moody’s and Fitch on all securities is positive.
OnIn April 20, 2005, Beaver County Industrial Development Authority2006, pollution control bonds aggregating $45notes that were formerly obligations of TE were refinanced and became obligations of FGCO and NGC. The proceeds from the refinancings were used to repay a portion of their associated company notes payable to TE. With those repayments, TE redeemed pollution control notes in the aggregate principal amount of $54 million were refunded. The new bonds were issued in a Dutch Auctionhaving variable interest rate mode, insured with municipal bond insurance and secured by FMB.rates.
Cash Flows From Investing Activities
Net cash used for investing activities increased by $15 millionwas effectively unchanged in the first quarter of 2005 from2006 compared to the same period of 2004. This increase was primarily due to increased2005. Decreases in property additions and net activity for the nuclear decommissioning trust funds were offset by increased loans to associated companies, partially offset by the reduction in lessor note investments.companies.
TE’s capital spending for the last three quarters of 20052006 is expected to be about $46 million (excluding $1 million for nuclear fuel).$47 million. These cash requirements are expected to be satisfied from a combination of internal cash, funds raised in the long-term capital markets (up to $100 million) and short-term borrowings.
credit arrangements. TE’s capital spending for the period 2005-20072006-2010 is expected to be about $192$236 million (excluding nuclear fuel) of which approximately $56$62 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to total approximately $54 million, of which about $8 million applies to 2005. During the same periods, TE’s nuclear fuel investments are expected to be reduced by approximately $64 million and $20 million, respectively, as the nuclear fuel is consumed.2006.
Off-Balance Sheet Arrangements
Obligations not included on TE’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of March 31, 2005,2006, the present value of these operating lease commitments, net of trust investments, totaled $566$535 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 $48 million of off-balance sheet financing as of March 31, 2005.
Equity Price RiskOUTLOOK
Included in TE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $194 million and $188 as of March 31, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $19 million reduction in fair value as of March 31, 2005. Changes in the fair value of these investments are recorded on OCI unless recognized as a result of sales or recognized as regulatory assets or liabilities.
Outlook
The electric industry continues to transition to a more competitive environment and all of TE'sTE’s customers can select alternative energy suppliers. TE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. TE has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
Regulatory Matters
In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of TE's customers elects to obtain power from an alternative supplier, TE reduces the customer's bill with a "generation shopping credit," based on the generation component plus an incentive, and the customer receives a generation charge from the alternative supplier. TE has continuing PLR responsibility to its franchise customers through December 31, 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.
TE's revised Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, and continues TE's support of energy efficiency and economic development efforts. Other key components of the revised Rate Stabilization Plan include the following:
· | extension of the amortization period for transition costs being recovered through the RTC from mid-2007 to as late as mid-2008; |
· | deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and |
· | ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes. |
On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may require TE to undertake, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. Any acceptance of future competitive bid results would terminate the Rate Stabilization Plan pricing, but not the related approved accounting, and not until twelve months after the PUCO authorizes such termination.
On December 30, 2004, TE filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $0.1 million in transmission and ancillary service costs beginning January 1, 2006. TE also filed an application for authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ATSI rate increase, as applicable, from October 1, 2003 through December 31, 2005.
TE records as regulatoryRegulatory assets are costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, withoutor for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income whenas incurred. TE'sAll regulatory assets are expected to be recovered under the provisions of TE’s regulatory plans. TE’s regulatory assets as of March 31, 2006 and December 31, 2005 were $276 million and $287 million, respectively.
On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming that order with respect to the approval of the rate stabilization charge, approval of the shopping credits, the grant of interest on shopping credit incentive deferral amounts, and approval of FirstEnergy’s financial separation plan. It remanded the approval of the RSP pricing back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient customer participation in the competitive marketplace.
Under provisions of the RSP, the PUCO had required the Ohio Companies to undertake a CBP to secure generation and allow for customer pricing participation in the competitive marketplace. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until 12 months after the PUCO authorizes such termination. On December 9, 2004, the PUCO rejected the auction price results from the CBP for the generation supply period beginning January 1, 2006 and issued an entry stating that the pricing under the approved revised RSP would take effect on January 1, 2006. On February 23, 2006 the CBP auction manager, National Economic Research Associates, notified the PUCO that a subsequent CBP to potentially provide firm generation service for the Ohio Companies' 2007 and 2008 actual load requirements could not proceed due to lack of interest, as there were no bidder applications submitted. Additionally, on March 20, 2006, the PUCO denied applications for rehearing filed by various parties regarding the PUCO's rules for the CBP. The above May 3, 2006 Supreme Court of Ohio opinion may require the PUCO to reconsider this customer pricing process.
On January 4, 2006, the PUCO approved, with modifications, TE's RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:
| · | Maintaining the existing level of base distribution rates through December 31, 2008 for TE; |
| · | Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred by all the Ohio Companies during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years; |
| · | Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for TE; |
| · | Reducing the deferred shopping incentive balances as of January 1, 2006 by up to $45 million for TE by accelerating the application of its accumulated cost of removal regulatory liability; and |
| · | Recovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all OE and TE distribution and transmission customers through a fuel recovery mechanism. The Ohio Companies may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the amount collected through the fuel recovery mechanism (in lieu of implementation of the GCAF rider). |
The following table provides the estimated amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2006 through 2008:
Amortization | | | | Period | | Amortization | | | | | (In millions) | | | 2006 | | $ | 83 | | | 2007 | | | 90 | | | 2008 | | | 108 | | Total Amortization | | $ | 281 | |
The PUCO’s January 4, 2006 approval of the RCP also included approval of the Ohio Companies’ supplemental stipulation which was filed with the PUCO on November 4, 2005 and which was an additional component of the RCP filed on September 9, 2005. On January 10, 2006, the Ohio Companies filed a Motion for Clarification of the PUCO order approving the RCP. The Ohio Companies sought clarity on issues related to distribution deferrals, including requirements of the review process, timing for recognizing certain deferrals and definitions of the types of qualified expenditures. The Ohio Companies also sought confirmation that the list of deferrable distribution expenditures originally included in the revised stipulation fall within the PUCO order definition of qualified expenditures. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies’ requests to: | · | Recognize fuel and distribution deferrals commencing January 1, 2006; | | | | | · | Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff; | | | | | · | Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and | | | | | · | Clarify that distribution expenditures do not have to be “accelerated” in order to be deferred. |
The PUCO approved the Ohio Companies’ methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies’ Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. The Ohio Companies responded to the applications for rehearing on February 13, 2006. In an Entry on Rehearing issued by the PUCO on March 1, 2006, all motions for rehearing were denied. Certain of these parties have subsequently filed their notices of appeal with the Supreme Court of Ohio alleging various errors made by the PUCO in its order approving the RCP.
On December 30, 2004, were $349 millionTE filed with the PUCO two applications related to the recovery of transmission and $375 million, respectively.ancillary service related costs. The first application sought recovery of these costs beginning January 1, 2006. TE is deferring customer shopping incentives and interestrequested that these costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $98 million as of March 31, 2005 and will be recovered through a surcharge raterider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues expected to be recovered from January through June 2006 are approximately $8 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. On May 1, 2006, TE filed a modification to the rider to determine revenues from July 2006 through June 2007.
The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for TE to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized TE to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of TE's case with a similar case involving Dayton Power & Light Company. Oral argument is currently scheduled for May 10, 2006.
On January 20, 2006 the OCC sought rehearing of the PUCO approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The OCC's brief is expected to be filed during the second quarter of 2006. The briefs of the PUCO and TE will be due within thirty days of the OCC's filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On April 18, 2006, the Court denied both parts of the motion but on its own motion consolidated the OCC's appeal of TE's case with a similar case of Dayton Power & Light Company and stayed briefing on these appeals.
On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies at a price equal to the RTC rateretail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio competitive bid process results in effect when the transition costs have been fully recovered. Recovery of the new regulatory assets will begina lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at that time and amortization of the regulatory assets for each accounting period will bea fixed price equal to the surcharge revenue recognizedretail generation price during that period.2006. The PPUC approved Penn's plan with modifications on April 20, 2006 to use an RFP process to obtain its power supply requirements after 2006.
On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticized the Ohio competitive bid process, and required FES to submit additional evidence in support of the reasonableness of the prices charged in the power sales agreements. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in late January 2007, as a result of the April 20, 2006 extension of the procedural schedule. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order and the FERC granted rehearing for future consideration on March 1, 2006.
See Note 1311 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.
Environmental Matters
TE accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably determineestimate the amount of such costs. Unasserted claims are reflected in TE'sTE’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
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 March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 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. CAIR will require additional reductions of NOx and SO2 emissions in two phases (Phase I in 2009 for NOx, 2010 for SO2 and Phase II in 2015 for both NOx and SO2). TE's Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO2 and NOx emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOx emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOx cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which TE operates 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 March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline by 2010 as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. The future cost of compliance with these regulations may be substantial.
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 United States 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 percent through 2012.
TE 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 KWH of electricity generated by TE is lower than many regional competitors due to TE's diversified generation sources which include low or non-CO2 emitting gas-fired and nuclear generators.
FirstEnergy plans to issue a report that will disclose the Companies’ environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by December 1, 2005 and will post the report on its website,www.firstenergycorp.com.
Regulation of Hazardous Waste
TE has been named 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 Sheet as of March 31, 2005,2006, based on estimates of the total costs of cleanup, TE'sTE’s proportionate responsibility for such costs and the financial ability of other nonaffiliatedunaffiliated entities to pay. Included in CurrentOther Noncurrent Liabilities are accrued liabilities aggregating approximately $0.2 million as of March 31, 2005. TE accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs 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.2006.
See Note 12(B)10(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.
Other Legal Proceedings
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to TE'sTE’s normal business operations pending against TE and its subsidiaries.TE. The most significantother potentially material items not otherwise discussed above are described below.
Power Outages and Related Litigation-
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. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,concluded, 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 real-time 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 contained 46 "recommendations“recommendations to prevent or minimize the scope of future blackouts."” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in process,new or material upgrades to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother applicable government agencies and reliability coordinators may, however, 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 asFinally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of March 31, 2005 forcontrol room operators before determining the next steps, if any, expenditures in excess of those actually incurred through that date.the proceeding.
Three substantially similar actionsFirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in various Ohio State courts by plaintiffs seekingbut were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent customers whoothers as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of the four cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc. as well) for claims paid to insureds for damages allegedly suffered damagesarising as a result of the loss of power on August 14, 2003 power outages. All three2003. The listed insureds in these cases, werein many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. On March 7, 2006, the PUCO issued a ruling applicable to all pending cases. Among its various rulings, the PUCO consolidated all of the pending outage cases for hearing; limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence; and gave the plaintiffs additional time to amend their complaints to otherwise comply with the PUCO's underlying order. The plaintiffs in one case have since filed an amended complaint. The named FirstEnergy companies have answered and also have filed a motion to dismiss the action, which is pending. Also, most complainants, along with the FirstEnergy companies, filed applications for lackrehearing with the PUCO over various rulings contained in the March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow the insurance company claimants, as insurers, to prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities which provide their service. The PUCO denied all other motions for rehearing. No estimate of jurisdiction. One case was refiled on January 12, 2004 at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. In the remaining case, the Courtpotential liability is available for any of Appeals on March 31, 2005 affirmed the trial court’s decision dismissing the case. It is not yet known whether further appeal will be sought.these cases. In addition to the one case that was refiled at the PUCO,these six cases, 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 Following the PUCO's March 7, 2006 order, that action was filed on August 25, 2004 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 timetable for a decision on the motion to dismiss has been establishedvoluntarily dismissed by the Court. No damage estimate has been provided and thus potential liability has not been determined.claimants.
FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against 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.
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 Nuclear Power Station, in which TE has a 48.62% interest. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse.
On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head described above. Under the NRC’s letter, FENOC has ninety days to respond to this NOV. TE has accrued the remaining liability for its share of the proposed fine of $1.6 million during the first quarter of 2005.Other Legal Matters-
If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability based on the Davis-Besse head degradation, it could have a material adverse effect on FirstEnergy's or any of its subsidiaries' financial condition and results of operations.
On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. FENOC operates the Perry Nuclear Power Plant, in which TE has a 19.91% interest. On April 4, 2005, the NRC held a public forum to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives although it remained under the heightened NRC oversight since August 2004. During the public forum and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.
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,the Ohio Companies, and the Davis-Besse extended outage, have 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. On December 30, 2004, FirstEnergy received a second subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse related disclosures, which FirstEnergy has provided. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.
The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will decide this case.
If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, and results of operations.operations and cash flows.
See Note 12(C)10(C) to the consolidated financial statements for further details and a complete discussion of these and other legal proceedings.
New Accounting Standards and Interpretations
FIN 47,“AccountingEITF Issue 04-13, "Accounting for Conditional Asset Retirement Obligations - an interpretationPurchases and Sales of FASB Statement No. 143”Inventory with the Same Counterparty"
On March 30, 2005, the FASB issued this interpretation to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. FirstEnergy is currently evaluating the effect this standard will have on the financial statements.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
In March 2004,September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus on the application guidancethat an exchange of inventory should be accounted 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 valuevalue. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and the impairment loss recognizedother storable inventory. Therefore, TE will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective forinterim or annual periods beginning after JuneMarch 15, 2004, were delayed by the issuance of FSP2006. This EITF 03-1-1 in September 2004. During the period of delay, FirstEnergyissue will continue to evaluate its investments as required by existing authoritative guidance.not have a material impact on TE's financial results.
SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140”
In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. TE is currently evaluating the impact of this Statement on its financial statements.
PENNSYLVANIA POWER COMPANY | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | March 31, | | | | | | | | | | | | | | | | 2005 | | 2004 | | | | | | | | | | | STATEMENTS OF INCOME | | | | (In thousands) | | | | | | | | | | | OPERATING REVENUES | | | | | $ | 134,484 | | $ | 142,623 | | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | Fuel | | | | | | 5,620 | | | 6,206 | | | Purchased power | | | | | | 46,980 | | | 48,508 | | | Nuclear operating costs | | | | | | 19,948 | | | 18,623 | | | Other operating costs | | | | | | 12,768 | | | 13,685 | | | Provision for depreciation | | | | | | 3,694 | | | 3,362 | | | Amortization of regulatory assets | | | | | | 9,882 | | | 10,076 | | | General taxes | | | | | | 6,472 | | | 6,634 | | | Income taxes | | | | | | 12,421 | | | 15,038 | | | Total operating expenses and taxes | | | | | | 117,785 | | | 122,132 | | | | | | | | | | | | | | OPERATING INCOME | | | | | | 16,699 | | | 20,491 | | | | | | | | | | | | | | OTHER INCOME (EXPENSE) (net of income taxes) | | | | | | (745 | ) | | 982 | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | Interest expense | | | | | | 2,319 | | | 2,725 | | | Allowance for borrowed funds used during construction | | | | | | (1,367 | ) | | (922 | ) | | Net interest charges | | | | | | 952 | | | 1,803 | | | | | | | | | | | | | | NET INCOME | | | | | | 15,002 | | | 19,670 | | | | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | | | | 640 | | | 640 | | | | | | | | | | | | | | EARNINGS ON COMMON STOCK | | | | | $ | 14,362 | | $ | 19,030 | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | | | | $ | 15,002 | | $ | 19,670 | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME | | | | | | -- | | | -- | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | | | | $ | 15,002 | | $ | 19,670 | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral partof these statements. | | | | | | | | | | | | | |
PENNSYLVANIA POWER COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | | Three Months Ended | | | | | March 31, | | | | | 2006 | | 2005 | | STATEMENTS OF INCOME | | (In thousands) | | | | | | | | | OPERATING REVENUES | | $ | 82,719 | | $ | 134,484 | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | Fuel | | | - | | | 5,620 | | | Purchased power | | | 54,756 | | | 46,980 | | | Nuclear operating costs | | | - | | | 19,948 | | | Other operating costs | | | 14,204 | | | 12,768 | | | Provision for depreciation | | | 2,431 | | | 3,694 | | | Amortization of regulatory assets | | | 3,411 | | | 9,882 | | | General taxes | | | 5,834 | | | 6,472 | | | Income taxes (benefit) | | | (251 | ) | | 12,421 | | | Total operating expenses and taxes | | | 80,385 | | | 117,785 | | | | | | | | | | | OPERATING INCOME | | | 2,334 | | | 16,699 | | | | | | | | | | | OTHER INCOME (EXPENSE) (net of income taxes) | | | 2,333 | | | (745 | ) | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | Interest on long term debt | | | 1,246 | | | 2,054 | | | Allowance for borrowed funds used during construction | | | (34 | ) | | (1,367 | ) | | Other interest expense | | | 2,709 | | | 265 | | | Net interest charges | | | 3,921 | | | 952 | | | | | | | | | | | NET INCOME | | | 746 | | | 15,002 | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | 156 | | | 640 | | | | | | | | | | | EARNINGS ON COMMON STOCK | | $ | 590 | | $ | 14,362 | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | NET INCOME | | $ | 746 | | $ | 15,002 | | | | | | | | | | | OTHER COMPREHENSIVE INCOME | | | - | | | - | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 746 | | $ | 15,002 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are | | | | | | an integral part of these statements. | | | | | | | |
PENNSYLVANIA POWER COMPANY | | | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | | | March 31, | | December 31, | | | | | | | 2005 | | 2004 | | | | | | | (In thousands) | | ASSETS | | | | | | | | UTILITY PLANT: | | | | | | | | | In service | | | | | $ | 873,780 | | $ | 866,303 | | | Less - Accumulated provision for depreciation | | | | | | 364,354 | | | 356,020 | | | | | | | | | 509,426 | | | 510,283 | | | Construction work in progress- | | | | | | | | | | | | Electric plant | | | | | | 121,145 | | | 104,366 | | | Nuclear fuel | | | | | | 7,647 | | | 3,362 | | | | | | | | | 128,792 | | | 107,728 | | | | | | | | | 638,218 | | | 618,011 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | Nuclear plant decommissioning trusts | | | | | | 142,317 | | | 143,062 | | | Long-term notes receivable from associated companies | | | | | | 32,890 | | | 32,985 | | | Other | | | | | | 530 | | | 722 | | | | | | | | | 175,737 | | | 176,769 | | CURRENT ASSETS: | | | | | | | | | | | | Cash and cash equivalents | | | | | | 38 | | | 38 | | | Notes receivable from associated companies | | | | | | 545 | | | 431 | | | Receivables- | | | | | | | | | | | | Customers (less accumulated provisions of $940,000 and $888,000, | | | | | | | | | | | | respectively, for uncollectible accounts) | | | | | | 42,984 | | | 44,282 | | | Associated companies | | | | | | 13,019 | | | 23,016 | | | Other | | | | | | 1,059 | | | 1,656 | | | Materials and supplies, at average cost | | | | | | 37,705 | | | 37,923 | | | Prepayments and other | | | | | | 22,405 | | | 8,924 | | | | | | | | | 117,755 | | | 116,270 | | | | | | | | | | | | | | DEFERRED CHARGES | | | | | | 9,921 | | | 10,106 | | | | | | | | $ | 941,631 | | $ | 921,156 | | CAPITALIZATION AND LIABILITIES | | | | | | | | | | | CAPITALIZATION: | | | | | | | | | | | | Common stockholder's equity- | | | | | | | | | | | | Common stock, $30 par value, authorized 6,500,000 shares - | | | | | | | | | | | | 6,290,000 shares outstanding | | | | | $ | 188,700 | | $ | 188,700 | | | Other paid-in capital | | | | | | 64,690 | | | 64,690 | | | Accumulated other comprehensive loss | | | | | | (13,706 | ) | | (13,706 | ) | | Retained earnings | | | | | | 94,057 | | | 87,695 | | | Total common stockholder's equity | | | | | | 333,741 | | | 327,379 | | | Preferred stock | | | | | | 39,105 | | | 39,105 | | | Long-term debt and other long-term obligations | | | | | | 121,889 | | | 133,887 | | | | | | | | | 494,735 | | | 500,371 | | CURRENT LIABILITIES: | | | | | | | | | | | | Currently payable long-term debt | | | | | | 38,524 | | | 26,524 | | | Accounts payable- | | | | | | | | | | | | Associated companies | | | | | | 43,569 | | | 46,368 | | | Other | | | | | | 1,345 | | | 1,436 | | | Notes payable to associated companies | | | | | | 10,644 | | | 11,852 | | | Accrued taxes | | | | | | 25,475 | | | 14,055 | | | Accrued interest | | | | | | 1,614 | | | 1,872 | | | Other | | | | | | 9,156 | | | 8,802 | | | | | | | | | 130,327 | | | 110,909 | | NONCURRENT LIABILITIES: | | | | | | | | | | | | Accumulated deferred income taxes | | | | | | 89,060 | | | 93,418 | | | Accumulated deferred investment tax credits | | | | | | 3,150 | | | 3,222 | | | Asset retirement obligation | | | | | | 140,560 | | | 138,284 | | | Retirement benefits | | | | | | 50,116 | | | 49,834 | | | Regulatory liabilities | | | | | | 26,523 | | | 18,454 | | | Other | | | | | | 7,160 | | | 6,664 | | | | | | | | | 316,569 | | | 309,876 | | COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | | | | | | | | $ | 941,631 | | $ | 921,156 | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets. | | | | | | | | | | | | | |
PENNSYLVANIA POWER COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | March 31, | | December 31, | | | | | 2006 | | 2005 | | | | | (In thousands) | | ASSETS | | | | | | UTILITY PLANT: | | | | | | | In service | | $ | 364,663 | | $ | 359,069 | | | Less - Accumulated provision for depreciation | | | 130,346 | | | 129,118 | | | | | | 234,317 | | | 229,951 | | | Construction work in progress- | | | | | | | | | Electric plant | | | 2,301 | | | 3,775 | | | | | | 236,618 | | | 233,726 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Long-term notes receivable from associated companies | | | 283,125 | | | 283,248 | | | Other | | | 351 | | | 351 | | | | | | 283,476 | | | 283,599 | | CURRENT ASSETS: | | | | | | | | | Cash and cash equivalents | | | 41 | | | 24 | | | Notes receivable from associated companies | | | 10,833 | | | 1,699 | | | Receivables - | | | | | | | | | Customers (less accumulated provisions of $1,092,000 and $1,087,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 39,510 | | | 44,555 | | | Associated companies | | | 80,186 | | | 115,441 | | | Other | | | 1,239 | | | 2,889 | | | Prepayments and other | | | 22,561 | | | 86,995 | | | | | | 154,370 | | | 251,603 | | | | | | | | | | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Prepaid pension costs | | | 42,649 | | | 42,243 | | | Other | | | 1,955 | | | 3,829 | | | | | | 44,604 | | | 46,072 | | | | | | | | | | | | | | $ | 719,068 | | $ | 815,000 | | CAPITALIZATION AND LIABILITIES | | | | | | | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity | | | | | | | | | Common stock, $30 par value, authorized 6,500,000 shares- | | | | | | | | | 6,290,000 shares outstanding | | $ | 188,700 | | $ | 188,700 | | | Other paid in capital | | | 71,136 | | | 71,136 | | | Retained earnings | | | 37,687 | | | 37,097 | | | Preferred stock | | | 14,105 | | | 14,105 | | | Long-term debt and other long-term obligations | | | 123,807 | | | 130,677 | | | | | | 435,435 | | | 441,715 | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | | 22,424 | | | 69,524 | | | Short-term borrowings - | | | | | | | | | Associated companies | | | - | | | 12,703 | | | Other | | | 19,000 | | | - | | | Accounts payable - | | | | | | | | | Associated companies | | | 20,538 | | | 73,444 | | | Other | | | 1,666 | | | 1,828 | | | Accrued taxes | | | 32,806 | | | 28,632 | | | Accrued interest | | | 1,059 | | | 1,877 | | | Other | | | 6,620 | | | 8,086 | | | | | | 104,113 | | | 196,094 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 63,683 | | | 66,576 | | | Retirement benefits | | | 46,429 | | | 45,967 | | | Regulatory liabilities | | | 63,781 | | | 58,637 | | | Other | | | 5,627 | | | 6,011 | | | | | | 179,520 | | | 177,191 | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | $ | 719,068 | | $ | 815,000 | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets. | | | | | | | | | | | | |
PENNSYLVANIA POWER COMPANY | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | March 31, | | | | | | | | | | | | | | | | 2005 | | 2004 | | | | | | | | | | | | | | | | (In thousands) | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | Net income | | | | | $ | 15,002 | | $ | 19,670 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | | | Provision for depreciation | | | | | | 3,694 | | | 3,362 | | | Amortization of regulatory assets | | | | | | 9,882 | | | 10,076 | | | Nuclear fuel and other amortization | | | | | | 4,140 | | | 4,565 | | | Deferred income taxes and investment tax credits, net | | | | | | (2,311 | ) | | (1,806 | ) | | Decrease (Increase) in operating assets- | | | | | | | | | | | | Receivables | | | | | | 11,892 | | | (214 | ) | | Materials and supplies | | | | | | 218 | | | (1,075 | ) | | Prepayments and other current assets | | | | | | (13,481 | ) | | (13,333 | ) | | Increase (Decrease) in operating liabilities- | | | | | | | | | | | | Accounts payable | | | | | | (2,890 | ) | | 3,740 | | | Accrued taxes | | | | | | 11,420 | | | 8,809 | | | Accrued interest | | | | | | (258 | ) | | (1,956 | ) | | Other | | | | | | 778 | | | 2,857 | | | Net cash provided from operating activities | | | | | | 38,086 | | | 34,695 | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | New Financing- | | | | | | | | | | | | Short-term borrowings, net | | | | | | -- | | | 29,084 | | | Redemptions and Repayments- | | | | | | | | | | | | Long-term debt | | | | | | -- | | | (42,302 | ) | | Short-term borrowings, net | | | | | | (1,208 | ) | | -- | | | Dividend Payments- | | | | | | | | | | | | Common stock | | | | | | (8,000 | ) | | (8,000 | ) | | Preferred stock | | | | | | (640 | ) | | (640 | ) | | Net cash used for financing activities | | | | | | (9,848 | ) | | (21,858 | ) | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | Property additions | | | | | | (28,522 | ) | | (13,998 | ) | | Contributions to nuclear decommissioning trusts | | | | | | (399 | ) | | (399 | ) | | Loans to associated companies | | | | | | (19 | ) | | (116 | ) | | Other | | | | | | 702 | | | 1,676 | | | Net cash used for investing activities | | | | | | (28,238 | ) | | (12,837 | ) | | | | | | | | | | | | | | Net change in cash and cash equivalents | | | | | | -- | | | -- | | | Cash and cash equivalents at beginning of period | | | | | | 38 | | | 40 | | | Cash and cash equivalents at end of period | | | | | $ | 38 | | $ | 40 | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integralpart of these statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
PENNSYLVANIA POWER COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | Three Months Ended | | | | | March 31, | | | | | 2006 | | 2005 | | | | | (In thousands) | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 746 | | $ | 15,002 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | Provision for depreciation | | | 2,431 | | | 3,694 | | | Amortization of regulatory assets | | | 3,411 | | | 9,882 | | | Nuclear fuel and other amortization | | | - | | | 4,140 | | | Deferred income taxes and investment tax credits, net | | | (2,348 | ) | | (2,311 | ) | | Decrease (increase) in operating assets- | | | | | | | | | Receivables | | | 41,950 | | | 11,892 | | | Materials and supplies | | | - | | | 218 | | | Prepayments and other current assets | | | 64,433 | | | (13,481 | ) | | Increase (decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | (53,068 | ) | | (2,890 | ) | | Accrued taxes | | | 4,175 | | | 11,420 | | | Accrued interest | | | (819 | ) | | (258 | ) | | Other | | | 1,607 | | | 778 | | | Net cash provided from operating activities | | | 62,518 | | | 38,086 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Short-term borrowings, net | | | 6,297 | | | - | | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (54,462 | ) | | - | | | Short-term borrowings, net | | | - | | | (1,208 | ) | | Dividend Payments- | | | | | | | | | Common stock | | | - | | | (8,000 | ) | | Preferred stock | | | (156 | ) | | (640 | ) | | Net cash used for financing activities | | | (48,321 | ) | | (9,848 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (5,114 | ) | | (28,522 | ) | | Proceeds from nuclear decommissioning trust fund sales | | | - | | | 13,703 | | | Investments in nuclear decommissioning trust funds | | | - | | | (14,102 | ) | | Loans to associated companies | | | (9,010 | ) | | (19 | ) | | Other | | | (56 | ) | | 702 | | | Net cash used for investing activities | | | (14,180 | ) | | (28,238 | ) | | | | | | | | | | | Net change in cash and cash equivalents | | | 17 | | | - | | | Cash and cash equivalents at beginning of period | | | 24 | | | 38 | | | Cash and cash equivalents at end of period | | $ | 41 | | $ | 38 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral | | | | | part of these statements. | | | | | | | | | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the StockholdersStockholder and Board of Directors of Pennsylvania Power Company:
We have reviewed the accompanying consolidated balance sheet of Pennsylvania Power Company and its subsidiary as of March 31, 2005,2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 20052006 and 2004.2005. 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 as of December 31, 2004,2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004;(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(G) and Note 8 to those consolidated financial statements) dated March 7, 2005,February 27, 2006, we expressed an unqualified opinions thereon. Theopinion on those consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein.statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004,2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP Cleveland, Ohio May 3, 20058, 2006
PENNSYLVANIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Penn is a wholly owned, electric utility subsidiary of OE. Penn conducts business in western Pennsylvania, providing regulated electric distribution services. Penn also provides generation services to those customers electing to retain Penn as their power supplier. Penn provides power directly to wholesale customers under previously negotiated contracts. Penn has unbundled the price of electricity intoPenn's rate restructuring plan and its component elements - including generation, transmission, distribution andassociated transition charges.charge revenue recovery was completed in 2005. Its power supply requirements are provided by FES - an affiliated company.
FirstEnergy Intra-System Generation Asset Transfers
On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively.
On October 24, 2005, Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.
On December 16, 2005, Penn completed the intra-system transfer of its ownership interests in the nuclear generation assets to NGC through an asset spin-off in the form of a dividend. FENOC continues to operate and maintain the nuclear generation assets.
These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.
The transfers will affect Penn’s near-term results with reductions in both revenues and expenses. Revenues are reduced due to the termination of certain arrangements with FES, under which Penn previously sold its nuclear-generated KWH to FES and leased its non-nuclear generation assets to FGCO, a subsidiary of FES. Penn’s expenses are lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets. In addition, Penn receives interest income on associated company notes receivable from the transfer of its generation net assets. FES will continue to provide Penn’s PLR requirements under revised purchased power arrangements for the three-year period beginning January 1, 2006 (see Outlook -- Regulatory Matters).
The effects on Penn’s results of operations in the first quarter of 2006 compared to the first quarter of 2005 from the generation asset transfers are summarized in the following table: Intra-System Generation Asset Transfers | | | First Quarter 2006 vs. First Quarter 2005 Income Statement Effects | | Increase (Decrease) | | (In millions) | | | | Operating Revenues: | | | | | Non-nuclear generating units rent | | $ | (5 | ) | (a) | | Nuclear generated KWH sales | | | (39 | ) | (b) | | Total - Operating Revenues Effect | | | (44 | ) | | | | Operating Expenses and Taxes: | | | | | | | Fuel costs - nuclear | | | (6 | ) | (c) | | Nuclear operating costs | | | (20 | ) | (c) | | Provision for depreciation | | | (2 | ) | (d) | | Income taxes | | | (7 | ) | (g) | | Total- Operating Expenses and Taxes Effect | | | (35 | ) | | | | Operating Income Effect | | | (9 | ) | | | | Other Income: | | | | | | | Interest income from notes receivable | | | 2 | | (e) | | Income taxes | | | 1 | | (g) | | Total-Other Income Effect | | | 1 | | | | | Net interest Charges: | | | | | | | Allowance for funds used during construction | | | (1 | ) | (f) | | Total-Net Interest Charges Effect | | | 1 | | | | | Net Income Effect | | $ | (9 | ) | | | | | | | | | | | | (a) Elimination of non-nuclear generation assets lease to FGCO. | | (b) Reduction of nuclear generated wholesale KWH sales to FES. | | (c) Reduction of nuclear fuel and operating costs. | (d) Reduction of depreciation expense and asset retirement obligation accretion related to generation assets. | | (e) Interest income on associated company notes receivable from the transfer of generation net assets. | (f) Reduction of allowance for borrowed funds used during construction on nuclear capital expenditures. | | (g) Income tax effect of the above adjustments. | |
Results of Operations
Earnings on common stock in the first quarter of 20052006 decreased to $14$0.6 million from $19$14 million in the first quarter of 2004.2005. The lower earnings resulted principally from decreased operating revenues, partially offset by lower operating expenses and taxes and lower net interest charges.the generation asset transfer effects shown in the table above.
Operating Revenues
Operating revenues decreased by $8$52 million, or 6%39%, in the first quarter of 20052006 as compared with the first quarter of 2004. The lower2005, primarily due to the generation asset transfer impact discussed in the table above. Excluding the effects of the asset transfer, operating revenues primarilydecreased by $8 million, or 9%. That decrease resulted from alower distribution revenues of $9 million primarily reflecting the completion of Penn's transition costs recovery, and lower wholesale revenues of $6 million resulting from the termination of a wholesale sales agreement with a non-affiliate in December 2005. The decrease in distribution KWH deliveries to residential and commercial customers reflected milder weather in the first quarter of 2006. The distribution and wholesale sales to FES due to less nuclear generation available for sale. Higherrevenue decreases were partially offset by an increase in retail generation sales revenues of $3$6 million, resultedprimarily from higher commercial and industrial sales of $1 million and $2 million, respectively, as a result of higher composite unit prices and increasedassociated with a 5% rate increase permitted by the PPUC for all customer classes - retail generation KWH sales. The increased sales reflected an improving service area economy including higher sales to the steel industry. These increases were partially offset by a $0.2 million residential revenues decrease reflecting lower sales volume (0.8%) and unit prices.remained substantially unchanged.
A $2 million reduction in distribution throughput revenues was primarily due to lower unit prices, partially offset by higher KWH deliveries to commercial and industrial customers. The lower unit prices are attributable to changes in Penn's CTC rate schedules in April 2004 as a result of the annual CTC reconciliation.
Changes in electric generation and distribution deliveries in the first quarter of 20052006 from the same quarter in 2004period of 2005 are summarized in the following table:
Changes in KWH SalesDistribution Deliveries | | | | Increase (Decrease) | | | | Electric Generation:Residential | | | (3 | )% | | Commercial | | | (1 | )% | | Industrial | | | 4 | % | RetailTotal Distribution Deliveries
| | | 0.7 | % | Wholesale
| | | (7.9 | )% | Total Electric Generation Sales | | | (4.3 | )% | | | | | | Distribution Deliveries: | | | | | Residential
| | | (0.8 | )% | Commercial
| | | 2.1 | % | Industrial
| | | 1.3 | % | Total Distribution Deliveries | | | 0.7- | % |
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $4$37 million in the first quarter of 20052006 from the first quarter of 2004.Lower fuel2005 principally due to the generation asset transfer impact as shown in the table above. Excluding the asset transfer effects, the following presents changes from the prior year by expense category:
Operating Expenses and Taxes - Changes (In millions) | | | | Increase (Decrease) | | | | | Purchased power costs | | $ | 8 | | | Other operating costs | | | 1 | | | Amortization of regulatory assets | | | (6 | ) | | Income taxes | | | (5 | ) | Total operating expenses and taxes | | $ | (2 | ) |
Increased purchased power costs in the first quarter of 2005,2006, compared with the samefirst quarter of 2004,2005, resulted from reduced nuclear generation. Lower purchased power costs in the first three months of 2005 reflected decreased KWH purchases and higher unit costs. Nuclearprices associated with the new power supply agreement with FES, partially offset by a 13% decrease in KWH purchased due to lower generation sales requirements. Other operating costs increased due to the Perry scheduled refueling outage (including an unplanned extension)transmission expenses associated with MISO Day 2 operations that began in April 2005.
Amortization of regulatory assets was lower in the first quarter of 2005 and the absence of nuclear refueling outages in2006 as compared to the same period last year. Other operating expenses decreased primarily because of lower employee benefit costs.2005 due to the completion of Penn's rate restructuring plan and related transition cost amortization.
Other Income (Expense)
Other income decreased $2increased $3 million in the first quarter of 2005,2006, compared with the first quarter of 2004,2005, in part due to the first quarter 2005impact of the generation asset transfer. Excluding the effects of the asset transfer, other income was $2 million higher. This increase was primarily due to the absence in 2006 of accruals for a potential $0.7 million civil penalty payable to the DOJ and $0.8 million settlement for potential contributions toward environmentally beneficialenvironmental projects related toin connection with the Sammis PlantNew Source Review settlement in the first quarter of 2005 (see Outlook - Environmental Matters) and the absence of a 2004 $1 million gain from the sale of an investment..
Net Interest Charges
Net Excluding the effects of the asset transfer, net interest charges continued to trend lower, decreasingincreased by $851,000$2 million in the first quarter of 2005 from the same period last year, reflecting redemptions of $22 million total principal amount of debt securities since2006, as compared to the first quarter of 2004.2005. This increase was primarily due to a loss incurred on reacquired pollution control notes in the first quarter of 2006.
Capital Resources and Liquidity
Penn’s cash requirements in 2005and thereafterfor2006 for operating expenses, construction expenditures and scheduled debt maturities and preferred stock redemptions are expected to be metwithmet with a combination of cash from operations and funds from the capital markets.short-term credit arrangements. Available borrowing capacity under credit facilities will be used to manage working capital requirements.
Changes in Cash Position
Penn had $38,000$41,000 of cash and cash equivalents as of March 31, 2005 and2006 compared with $24,000 as of December 31, 2004.2005. The major sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Net cash provided from operating activities in the first quarter of 2005,2006, compared with the corresponding 20042005 period, was as follows:
| | | Three Months Ended | | | Three Months Ended | | | | | March 31, | | | March 31, | | Operating Cash Flows | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | (In millions) | | | | | | | | | | Cash earnings(1) | | $ | 30 | | $ | 38 | | | $ | 4 | | $ | 30 | | | Working capital and other | | | 8 | | | (3 | ) | | | 58 | | | 8 | | | | | | | | | | | | | | | | | | | Total Cash Flows from Operating Activities | | $ | 38 | | $ | 35 | | | | Net cash provided from operating activities | | | $ | 62 | | $ | 38 | |
| (1) | Cash earnings is a non-GAAP measure (see reconciliation below). |
(1)Cash earnings is a non-GAAP measure (see reconciliation below).Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. Penn believes that cash earnings isare a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.income:
| | | Three Months Ended | | | Three Months Ended | | | | | March 31, | | | March 31, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | (In millions) | | | Net Income (GAAP) | | $ | 15 | | $ | 20 | | | $ | 1 | | $ | 15 | | | Non-Cash Charges (Credits): | | | | | | | | | | | | | | | Provision for depreciation | | | 3 | | | 3 | | | | 2 | | | 3 | | Amortization of regulatory assets | | | 10 | | | 10 | | | | 3 | | | 10 | | Nuclear fuel and other amortization | | | 4 | | | 5 | | | | - | | | 4 | | Deferred income taxes and investment tax credits, net | | | (2 | ) | | (2 | ) | | | (2 | ) | | (2 | ) | Other non-cash expenses | | | -- | | | 2 | | | | - | | | - | | | Cash earnings (Non-GAAP) | | $ | 30 | | $ | 38 | | | $ | 4 | | $ | 30 | |
The $8$26 million decrease in cash earnings is described above under“Results “Results of OperationsOperations.”. The $11$50 million change in working capital change was primarily due to changesincreases in cash provided from the settlement of $12receivables of $30 million and a $78 million change in receivablesprepayments and $3 million in accrued taxes,other current assets, principally as a result of the asset transfer discussed above, partially offset by increased cash outflows from the settlement of accounts payable of $50 million and a $7 million change in accounts payable.accrued taxes.
Cash Flows From Financing Activities
Net cash used for financing activities totaled $48 million in the first quarter of 2006, compared with $10 million in the first quarter of 2005, compared with $222005. This increase resulted from $54 million of long-term debt redemptions in 2006 principally as a result of the generation asset transfer discussed above, partially offset by a net $8 million increase in short-term borrowings and the absence of $8 million in common stock dividend payments to OE in the first quarter of 2004. This decrease resulted from reduced debt redemptions in the first quarter of 2005, compared with the corresponding 2004 period.2005.
Penn had $583,000$11 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $11$19 million of short-term indebtedness with associated companies as of March 31, 2005.2006. Penn has authorization from the SEC, continued by FERC rules adopted as a result of EPACT's repeal of PUHCA, to incur short-term debt up to its charter limit of $49$50 million (including the utility money pool). Penn had the capability to issue $532$64 million of additional FMB on the basis of property additions and retired bonds as of March 31, 2005.2006. Based upon applicable earnings coverage tests, Penn could issue up to $367$415 million of preferred stock (assuming no additional debt was issued) as of March 31, 2005.2006.
Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to the full amount of $25 million available as of March 31, 2006 under a receivables financing arrangement which expires June 29, 2006. As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. As of March 31, 2006, the facility was drawn for $19 million.
Penn has the ability to borrow under a syndicated $2 billion five-year revolving credit facility, which expires in June 2010, along with FirstEnergy, OE, CEI, TE, JCP&L, Met-Ed, Penelec, FES, and ATSI. Borrowings under the facility are available to each Borrower separately and will mature on the earlier of 364 days from the date of borrowing or the commitment termination date. Penn's borrowing limit under the facility is $50 million.
Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding letters of credit will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under the existing credit facility and accounts receivable financing facilities totaled $56 million as of March 31, 2006.
The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of March 31, 2006, Penn's debt to total capitalization as defined under the revolving credit facility was 35%.
The facility does not contain any provisions that either restrict Penn's ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to Penn's credit ratings.
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.subsidiaries. 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 under these arrangements in the first quarter of 20052006 was 2.66%4.58%.
In addition, Penn has a $25 million receivables financing facility through its subsidiary. As of March 31, 2005, the facility was undrawn; it expires June 30, 2005 and is expected to be renewed.
On May 16, 2005, Penn intends to redeem all 127,500 outstanding shares of 7.625% preferred stock at $102.29 per share and all 250,000 outstanding shares of 7.75% preferred stock at $100 per share, both plus accrued dividends Penn's access to the date of redemption.
Penn’s access to capital markets and the costs of financing are dependent oninfluenced by the ratings of its securities and the securities of OE and FirstEnergy. The rating outlook from S&P on all securities is stable. Moody's and Fitch's ratings outlook on all securities is stable.
On March 18, 2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affect FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings outlook would be revised to positive.
In April 2006, pollution control notes that were formerly obligations of Penn were refinanced and became obligations of FGCO and NGC. The proceeds from the refinancings were used to repay a portion of their associated company notes payable to Penn. With those repayments, Penn redeemed pollution control notes in the principal amount of $6.95 million at 5.45%.
Cash Flows From Investing Activities
Net cash used infor investing activities totaled $28$14 million in the first quarter of 2005,2006, compared with $13$28 million in the same quarter of 2004.2005. The $15$14 million decrease in the 2006 period reflects a $23 million reduction in property additions, principally as a result of the generation asset transfer discussed above, partially offset by a $9 million increase in the 2005 period reflects an increase in property additions.loans to associated companies.
During the remaining three quarters of 2005,2006, capital requirements for property additions are expected to be about $67 million, including $9 million for nuclear fuel.$14 million. Penn has additionalsinking fund requirements of approximately $2$1 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2005.2006. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.
Penn’s capital spending for the period 2005-20072006-2010 is expected to be about $227$91 million (excluding nuclear fuel) of which approximately $82$19 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $64 million, of which about $13 million relates to 2005. During the same periods, Penn’s nuclear fuel investments are expected to be reduced by approximately $52 million and $17 million, respectively, as the nuclear fuel is consumed.2006. Penn had no other material obligations as of March 31, 20052006 that have not been recognized on its Consolidated Balance Sheet.
Equity Price Risk
Included in Penn’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $56 million and $57 million as of March 31, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6 million reduction in fair value as of March 31, 2005.
OutlookOUTLOOK
The electric industry continues to transition to a more competitive environment and all of Penn'sPenn’s customers can select alternative energy suppliers. Penn 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. Penn has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
Regulatory Matters Pennsylvania enacted its electric utility competition law in 1996 with the phase-in of customer choice for electric generation suppliers completed as of January 1, 2001. Penn's customer rates were restructured to itemize (unbundle) the current price of electricity into its component elements - including generation, transmission, distribution and stranded cost recovery. In the event customers obtain power from an alternative source, the generation portion of Penn’s rates is excluded from their bill and the customers receive a generation charge from the alternative supplier. The stranded cost recovery portion of rates provides for recovery of certain amounts not otherwise considered recoverable in a competitive generation market, including regulatory assets. Under the rate restructuring plan, Penn is entitled to recover $236 million of stranded costs through the CTC that began in 1999 and ends in 2006.
Regulatory assets and liabilities are costs which have been authorized by the PPUC and the FERC for recovery from or credit to customers in future periods and, without such authorization, would have been charged or credited to income when incurred. Penn'sPenn’s net regulatory liabilities were approximately $27$64 million and $18$59 million as of March 31, 20052006 and December 31, 2004,2005, respectively, and are included inunder Noncurrent Liabilities on the Consolidated Balance Sheets.
On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn recommended that an RFP process cover the period January 1, 2007 through May 31, 2008. Hearings were held on January 10, 2006 with main briefs filed on January 27, 2006 and reply briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a Recommended Decision to adopt Penn's RFP process with modifications. The PPUC approved the Recommended Decision with additional modifications on April 20, 2006. The approved plan is designed to provide customers with PLR service for January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.
On November 1, 2005, FES filed a power sales agreement for FERC approval that would permit Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. On December 29, 2005, the FERC issued an order setting the power sales agreement for hearing. The order required FES to submit additional evidence in support of the reasonableness of the prices charged in Penn’s contract. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in late January 2007, as a result of an April 20, 2006 extension of the procedural schedule. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order and the FERC granted rehearing for further consideration on March 1, 2006. See Note 1311 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania, including a more detailed discussion of reliability initiatives.Pennsylvania.
Environmental Matters
Penn accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably determineestimate the amount of such costs. Unasserted claims are reflected in Penn’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
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 March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 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. CAIR will require additional reductions of NOx and SO2emissions in two phases (Phase I in 2009 for NOx, 2010 for SO2 and Phase II in 2015 for both NOx and SO2). Penn's Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO2 and NOxemissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOx emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOx cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which Penn operates 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 March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline by 2010 as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. 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 coveringalleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which iswas owned at that time by OE and Penn. In addition, the U.S. Department of Justice (DOJ)DOJ filed eight civil complaints against various investor-owned utilities, which includedincluding 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. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement which is inwas approved by the form of a Consent Decree subject to a thirty-day public comment period that endedCourt on April 29,July 11, 2005, and final approval by the District Court Judge, requires OEreductions of NOx and Penn to reduceSO2 emissions fromat the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices requiring capitaland provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if OE and Penn fail to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, OE and Penn could be exposed to penalties under the settlement agreement. Capital expenditures necessary to meet those requirements are currently estimated to be $1.1$1.5 billion (primarily(the primary portion of which is expected to be spent in the 2008 to 2011 time period). On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million towardstoward environmentally beneficial projects, which include wind energy purchasepurchased power agreements over a 20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million (Penn's share is $0.7 million).million. Results for the first quarter of 2005 includeincluded the penalties payable by OE and Penn of $7.8 million and $0.7 million, penalty payable byrespectively. OE and Penn also recognized liabilities of $9.2 million and a $0.8 million, liabilityrespectively, for probable future cash contributions toward environmentally beneficial projects.
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 United States 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 percent through 2012.
Penn 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 KWH of electricity generated by Penn is lower than many regional competitors due to Penn's diversified generation sources which include low or non-CO2 emitting gas-fired and nuclear generators.
FirstEnergy plans to issue a report that will disclose the Companies’ environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by December 1, 2005 and will post the report on its web site,www.firstenergycorp.com.
Other Legal Proceedings
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Penn'sPenn’s normal business operations pending against Penn. The most significantother material items not otherwise discussed above are described below.
Power Outages and Related Litigation-
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'sFirstEnergy’s service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded,concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,concluded, 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 real-time 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 contained 46 "recommendations“recommendations to prevent or minimize the scope of future blackouts."” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far implementation of the recommendations has not required, nor is expected to require, substantial investment in process,new or material upgrades, to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother 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 asFinally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of March 31, 2005 forcontrol room operators before determining the next steps, if any, expenditures in excess of those actually incurred through that date.
One complaint was filed on August 25, 2004 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 timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thus potential liability has not been determined.proceeding.
FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against 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.
On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. FENOC operates the Perry Nuclear Power Plant, in which Penn has a 5.24% interest. On April 4, 2005, the NRC held a public forum to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives although it remained under the heightened NRC oversight since August 2004. During the public forum and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.
See Note 12(C)10(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.
New Accounting Standards and Interpretations
FIN 47,“Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143” | EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" |
On March 30,In September 2005, the FASB issued this interpretation to clarifyEITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the scopesame counterparty should be combined and timingconsidered as a single arrangement for purposes of liability recognition for conditional asset retirement obligations. Under this interpretation, companiesapplying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are required to recognizecombined and considered a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. FirstEnergy is currently evaluating the effect this standard will have on the financial statements.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
In March 2004,single arrangement, the EITF reached a consensus on the application guidancethat an exchange of inventory should be accounted 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 valuevalue. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and the impairment loss recognizedother storable inventory. Therefore, Penn adopted adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective forinterim or annual periods beginning after JuneMarch 15, 2004, were delayed by the issuance of FSP2006. This EITF 03-1-1 in September 2004. During the period of delay, FirstEnergyissue will continue to evaluate its investments as required by existing authoritative guidance.not have a material impact on Penn's financial results.
SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140” In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. Penn is currently evaluating the impact of this Statement on its financial statements.
JERSEY CENTRAL POWER & LIGHT COMPANY | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | March 31, | | | | | | | | | | | | | | | | 2005 | | 2004 | | | | | | | | | | | STATEMENTS OF INCOME | | | | (In thousands) | | | | | | | | | | | OPERATING REVENUES | | | | | $ | 529,092 | | $ | 498,124 | | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | Purchased power | | | | | | 277,132 | | | 270,733 | | | Other operating costs | | | | | | 101,067 | | | 86,816 | | | Provision for depreciation | | | | | | 20,206 | | | 19,075 | | | Amortization of regulatory assets | | | | | | 68,374 | | | 64,485 | | | General taxes | | | | | | 15,440 | | | 15,932 | | | Income taxes | | | | | | 12,483 | | | 9,113 | | | Total operating expenses and taxes | | | | | | 494,702 | | | 466,154 | | | | | | | | | | | | | | OPERATING INCOME | | | | | | 34,390 | | | 31,970 | | | | | | | | | | | | | | OTHER INCOME (net of income taxes) | | | | | | 44 | | | 1,503 | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | Interest on long-term debt | | | | | | 19,405 | | | 20,728 | | | Allowance for borrowed funds used during construction | | | | | | (403 | ) | | (120 | ) | | Deferred interest | | | | | | (911 | ) | | (923 | ) | | Other interest expense | | | | | | 1,824 | | | 390 | | | Net interest charges | | | | | | 19,915 | | | 20,075 | | | | | | | | | | | | | | NET INCOME | | | | | | 14,519 | | | 13,398 | | | | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | | | | 125 | | | 125 | | | | | | | | | | | | | | EARNINGS ON COMMON STOCK | | | | | $ | 14,394 | | $ | 13,273 | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | | | | $ | 14,519 | | $ | 13,398 | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | Unrealized gain (loss) on derivative hedges | | | | | | 69 | | | (14 | ) | | Unrealized loss on available for sale securities | | | | | | -- | | | (8 | ) | | Other comprehensive income (loss) | | | | | | 69 | | | (22 | ) | | Income tax related to other comprehensive income | | | | | | (28 | ) | | 3 | | | Other comprehensive income (loss), net of tax | | | | | | 41 | | | (19 | ) | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | | | | $ | 14,560 | | $ | 13,379 | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part | | | of these statements. | | | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | | | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | | | March 31, | | December 31, | | | | | | | 2005 | | 2004 | | | | | | | (In thousands) | | ASSETS | | | | | | | | UTILITY PLANT: | | | | | | | | | In service | | | | | $ | 3,755,666 | | $ | 3,730,767 | | | Less - Accumulated provision for depreciation | | | | | | 1,395,942 | | | 1,380,775 | | | | | | | | | 2,359,724 | | | 2,349,992 | | | Construction work in progress | | | | | | 76,054 | | | 75,012 | | | | | | | | | 2,435,778 | | | 2,425,004 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | Nuclear plant decommissioning trusts | | | | | | 137,142 | | | 138,205 | | | Nuclear fuel disposal trust | | | | | | 160,757 | | | 159,696 | | | Long-term notes receivable from associated companies | | | | | | 21,335 | | | 20,436 | | | Other | | | | | | 16,362 | | | 19,379 | | | | | | | | | 335,596 | | | 337,716 | | CURRENT ASSETS: | | | | | | | | | | | | Cash and cash equivalents | | | | | | 41 | | | 162 | | | Receivables- | | | | | | | | | | | | Customers (less accumulated provisions of $3,090,000 and $3,881,000, | | | | | | | | | | | | respectively, for uncollectible accounts) | | | | | | 201,196 | | | 201,415 | | | Associated companies | | | | | | 34,961 | | | 86,531 | | | Other (less accumulated provisions of $263,000 and $162,000, | | | | | | | | | | | | respectively, for uncollectible accounts) | | | | | | 76,837 | | | 39,898 | | | Materials and supplies, at average cost | | | | | | 2,352 | | | 2,435 | | | Prepayments and other | | | | | | 22,239 | | | 31,489 | | | | | | | | | 337,626 | | | 361,930 | | DEFERRED CHARGES: | | | | | | | | | | | | Regulatory assets | | | | | | 2,267,795 | | | 2,176,520 | | | Goodwill | | | | | | 1,983,740 | | | 1,985,036 | | | Other | | | | | | 4,568 | | | 4,978 | | | | | | | | | 4,256,103 | | | 4,166,534 | | | | | | | | $ | 7,365,103 | | $ | 7,291,184 | | CAPITALIZATION AND LIABILITIES | | | | | | | | | | | CAPITALIZATION: | | | | | | | | | | | | Common stockholder's equity- | | | | | | | | | | | | Common stock, $10 par value, authorized 16,000,000 shares - | | | | | | | | | | | | 15,371,270 shares outstanding | | | | | $ | 153,713 | | $ | 153,713 | | | Other paid-in capital | | | | | | 3,013,912 | | | 3,013,912 | | | Accumulated other comprehensive loss | | | | | | (55,493 | ) | | (55,534 | ) | | Retained earnings | | | | | | 37,665 | | | 43,271 | | | Total common stockholder's equity | | | | | | 3,149,797 | | | 3,155,362 | | | Preferred stock | | | | | | 12,649 | | | 12,649 | | | Long-term debt and other long-term obligations | | | | | | 1,229,210 | | | 1,238,984 | | | | | | | | | 4,391,656 | | | 4,406,995 | | CURRENT LIABILITIES: | | | | | | | | | | | | Currently payable long-term debt | | | | | | 22,381 | | | 16,866 | | | Notes payable- | | | | | | | | | | | | Associated companies | | | | | | 204,794 | | | 248,532 | | | Accounts payable- | | | | | | | | | | | | Associated companies | | | | | | 9,248 | | | 20,605 | | | Other | | | | | | 105,699 | | | 124,733 | | | Accrued taxes | | | | | | 41,503 | | | 2,626 | | | Accrued interest | | | | | | 25,078 | | | 10,359 | | | Other | | | | | | 68,192 | | | 65,130 | | | | | | | | | 476,895 | | | 488,851 | | NONCURRENT LIABILITIES: | | | | | | | | | | | | Power purchase contract loss liability | | | | | | 1,325,786 | | | 1,268,478 | | | Accumulated deferred income taxes | | | | | | 688,248 | | | 645,741 | | | Nuclear fuel disposal costs | | | | | | 171,014 | | | 169,884 | | | Asset retirement obligation | | | | | | 73,754 | | | 72,655 | | | Retirement benefits | | | | | | 98,307 | | | 103,036 | | | Other | | | | | | 139,443 | | | 135,544 | | | | | | | | | 2,496,552 | | | 2,395,338 | | COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | | | | | | | | $ | 7,365,103 | | $ | 7,291,184 | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these balance sheets. | | | | | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | (Unaudited) | | | | | | Three Months Ended | | | | | March 31, | | | | | 2006 | | 2005 | | | | | | | Restated | | STATEMENTS OF INCOME | | (In thousands) | | | | | | | | | OPERATING REVENUES | | $ | 575,792 | | $ | 529,092 | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | Purchased power | | | 315,710 | | | 277,132 | | | Other operating costs | | | 83,028 | | | 101,067 | | | Provision for depreciation | | | 20,628 | | | 20,206 | | | Amortization of regulatory assets | | | 66,745 | | | 68,374 | | | General taxes | | | 16,232 | | | 15,440 | | | Income taxes | | | 22,359 | | | 12,968 | | | Total operating expenses and taxes | | | 524,702 | | | 495,187 | | | | | | | | | | | OPERATING INCOME | | | 51,090 | | | 33,905 | | | | | | | | | | | OTHER INCOME (net of income taxes) | | | 2,344 | | | 44 | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | Interest on long-term debt | | | 18,059 | | | 19,405 | | | Allowance for borrowed funds used during construction | | | (892 | ) | | (403 | ) | | Deferred interest | | | (1,400 | ) | | (911 | ) | | Other interest expense | | | 3,957 | | | 2,409 | | | Net interest charges | | | 19,724 | | | 20,500 | | | | | | | | | | | NET INCOME | | | 33,710 | | | 13,449 | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | 125 | | | 125 | | | | | | | | | | | EARNINGS ON COMMON STOCK | | $ | 33,585 | | $ | 13,324 | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | NET INCOME | | $ | 33,710 | | $ | 13,449 | | | | | | | | | | | OTHER COMPREHENSIVE INCOME: | | | | | | | | | Unrealized gain on derivative hedges | | | 69 | | | 69 | | | Income tax expense related to other comprehensive income | | | 28 | | | 28 | | | Other comprehensive income, net of tax | | | 41 | | | 41 | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 33,751 | | $ | 13,490 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company | | | are an integral part of these statements. | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | March 31, | | | | | | | | | | | | | | | | 2005 | | 2004 | | | | | | | | | | | | | | | | (In thousands) | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | Net income | | | | | $ | 14,519 | | $ | 13,398 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | | | Provision for depreciation | | | | | | 20,206 | | | 19,075 | | | Amortization of regulatory assets | | | | | | 68,374 | | | 64,485 | | | Deferred costs, net | | | | | | (73,359 | ) | | (37,981 | ) | | Deferred income taxes and investment tax credits, net | | | | | | 7,169 | | | 230 | | | Accrued retirement benefit obligation | | | | | | (4,728 | ) | | (11,714 | ) | | Accrued compensation, net | | | | | | 5,413 | | | (855 | ) | | Decrease (Increase) in operating assets: | | | | | | | | | | | | Receivables | | | | | | 14,849 | | | 1,438 | | | Materials and supplies | | | | | | 82 | | | 358 | | | Prepayments and other current assets | | | | | | 9,250 | | | 24,376 | | | Increase (Decrease) in operating liabilities: | | | | | | | | | | | | Accounts payable | | | | | | (30,390 | ) | | (15,349 | ) | | Accrued taxes | | | | | | 38,877 | | | 49,480 | | | Accrued interest | | | | | | 14,719 | | | 10,778 | | | Other | | | | | | 12,321 | | | 4,323 | | | Net cash provided from operating activities | | | | | | 97,302 | | | 122,042 | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | Redemptions and Repayments- | | | | | | | | | | | | Long-term debt | | | | | | (3,883 | ) | | (3,591 | ) | | Short-term borrowings, net | | | | | | (43,738 | ) | | (79,744 | ) | | Dividend Payments- | | | | | | | | | | | | Common stock | | | | | | (20,000 | ) | | (5,000 | ) | | Preferred stock | | | | | | (125 | ) | | (125 | ) | | Net cash used for financing activities | | | | | | (67,746 | ) | | (88,460 | ) | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | Property additions | | | | | | (28,124 | ) | | (28,212 | ) | | Loans to associated companies, net | | | | | | (898 | ) | | (1,056 | ) | | Other | | | | | | (655 | ) | | (4,303 | ) | | Net cash used for investing activities | | | | | | (29,677 | ) | | (33,571 | ) | | | | | | | | | | | | | | Net increase (decrease) in cash and cash equivalents | | | | | | (121 | ) | | 11 | | | Cash and cash equivalents at beginning of period | | | | | | 162 | | | 271 | | | Cash and cash equivalents at end of period | | | | | $ | 41 | | $ | 282 | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of | | | these statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | | | CONSOLIDATED BALANCE SHEETS | (Unaudited) | | | | March 31, | | December 31, | | | | | 2006 | | 2005 | | | | | (In thousands) | ASSETS | | | | | | UTILITY PLANT: | | | | | | | In service | | $ | 3,935,904 | | $ | 3,902,684 | | | Less - Accumulated provision for depreciation | | | 1,453,740 | | | 1,445,718 | | | | | | 2,482,164 | | | 2,456,966 | | | Construction work in progress | | | 99,320 | | | 98,720 | | | | | | 2,581,484 | | | 2,555,686 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 149,398 | | | 145,975 | | | Nuclear fuel disposal trust | | | 165,198 | | | 164,203 | | | Other | | | 13,443 | | | 16,693 | | | | | | 328,039 | | | 326,871 | | CURRENT ASSETS: | | | | | | | | | Cash and cash equivalents | | | 103 | | | 102 | | | Notes receivable - associated companies | | | 21,551 | | | 18,419 | | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $3,225,000 and $3,830,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 218,926 | | | 258,077 | | | Associated companies | | | 2,342 | | | 203 | | | Other (less accumulated provisions of $227,000 and $204,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 30,463 | | | 41,456 | | | Materials and supplies, at average cost | | | 1,849 | | | 2,104 | | | Prepayments and other | | | 9,002 | | | 17,065 | | | | | | 284,236 | | | 337,426 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Regulatory assets | | | 2,167,886 | | | 2,226,591 | | | Goodwill | | | 1,978,350 | | | 1,985,858 | | | Prepaid pension costs | | | 149,407 | | | 148,054 | | | Other | | | 4,403 | | | 3,620 | | | | | | 4,300,046 | | | 4,364,123 | | | | | $ | 7,493,805 | | $ | 7,584,106 | | CAPITALIZATION AND LIABILITIES | | | | | | | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity- | | | | | | | | | Common stock, $10 par value, authorized 16,000,000 shares- | | | | | | | | | 15,371,270 shares outstanding | | $ | 153,713 | | $ | 153,713 | | | Other paid-in capital | | | 2,995,715 | | | 3,003,190 | | | Accumulated other comprehensive loss | | | (1,989 | ) | | (2,030 | ) | | Retained earnings | | | 64,475 | | | 55,890 | | | Total common stockholder's equity | | | 3,211,914 | | | 3,210,763 | | | Preferred stock | | | 12,649 | | | 12,649 | | | Long-term debt and other long-term obligations | | | 967,812 | | | 972,061 | | | | | | 4,192,375 | | | 4,195,473 | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | | 207,408 | | | 207,231 | | | Notes payable- | | | | | | | | | Associated companies | | | 278,158 | | | 181,346 | | | Accounts payable- | | | | | | | | | Associated companies | | | 5,793 | | | 37,955 | | | Other | | | 112,670 | | | 149,501 | | | Accrued taxes | | | 86,462 | | | 54,356 | | | Accrued interest | | | 33,685 | | | 19,916 | | | Cash collateral from suppliers | | | 32,568 | | | 141,225 | | | Other | | | 83,725 | | | 86,884 | | | | | | 840,469 | | | 878,414 | | NONCURRENT LIABILITIES: | | | | | | | | | Power purchase contract loss liability | | | 1,183,501 | | | 1,237,249 | | | Accumulated deferred income taxes | | | 814,797 | | | 812,034 | | | Nuclear fuel disposal costs | | | 176,981 | | | 175,156 | | | Asset retirement obligation | | | 80,729 | | | 79,527 | | | Retirement benefits | | | 72,905 | | | 72,454 | | | Other | | | 132,048 | | | 133,799 | | | | | | 2,460,961 | | | 2,510,219 | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | $ | 7,493,805 | | $ | 7,584,106 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part | | | of these balance sheets. | | | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | (Unaudited) | | | | | | Three Months Ended | | | | | March 31, | | | | | 2006 | | 2005 | | | | | | | Restated | | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 33,710 | | $ | 13,449 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | Provision for depreciation | | | 20,628 | | | 20,206 | | | Amortization of regulatory assets | | | 66,745 | | | 68,374 | | | Deferred purchased power and other costs | | | (61,868 | ) | | (73,359 | ) | | Deferred income taxes and investment tax credits, net | | | 3,826 | | | 7,169 | | | Accrued retirement benefit obligation | | | (902 | ) | | (4,728 | ) | | Accrued compensation, net | | | (1,834 | ) | | 5,413 | | | Cash collateral from (returned to) suppliers | | | (108,657 | ) | | 6,365 | | | Decrease (increase) in operating assets: | | | | | | | | | Receivables | | | 48,005 | | | 14,849 | | | Materials and supplies | | | 255 | | | 82 | | | Prepayments and other current assets | | | 8,063 | | | 9,250 | | | Increase (decrease) in operating liabilities: | | | | | | | | | Accounts payable | | | (68,993 | ) | | (30,390 | ) | | Accrued taxes | | | 32,106 | | | 39,363 | | | Accrued interest | | | 13,769 | | | 15,303 | | | Other | | | (5,773 | ) | | 5,956 | | | Net cash provided from (used for) operating activities | | | (20,920 | ) | | 97,302 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Short-term borrowings, net | | | 96,812 | | | - | | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (3,731 | ) | | (3,883 | ) | | Short-term borrowings, net | | | - | | | (43,738 | ) | | Dividend Payments- | | | | | | | | | Common stock | | | (25,000 | ) | | (20,000 | ) | | Preferred stock | | | (125 | ) | | (125 | ) | | Net cash provided from (used for) financing activities | | | 67,956 | | | (67,746 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (45,361 | ) | | (28,124 | ) | | Loans to associated companies, net | | | (3,132 | ) | | (898 | ) | | Proceeds from nuclear decommissioning trust fund sales | | | 45,865 | | | 28,351 | | | Investments in nuclear decommissioning trust funds | | | (46,588 | ) | | (29,075 | ) | | Other | | | 2,181 | | | 69 | | | Net cash used for investing activities | | | (47,035 | ) | | (29,677 | ) | | | | | | | | | | | Net increase (decrease) in cash and cash equivalents | | | 1 | | | (121 | ) | | Cash and cash equivalents at beginning of period | | | 102 | | | 162 | | | Cash and cash equivalents at end of period | | $ | 103 | | $ | 41 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an | | | integral part of these statements. | |
Report of Independent Registered Public Accounting Firm
To the StockholdersStockholder and Board of Directors of Jersey Central Power & Light Company:
We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of March 31, 2005,2006, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 20052006 and 2004.2005. 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 as of December 31, 2004,2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004;(not presented herein), and in our report (which contained references to the Company’s change inrestatement of its method of accountingpreviously issued consolidated financial statements for asset retirement obligations as of January 1,the years ended December 31, 2004 and 2003 as discussed in Note 9 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 62(I) to those consolidated financial statements) dated March 7, 2005,February 27, 2006, we expressed an unqualified opinions thereon. Theopinion on those consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein.statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004,2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP Cleveland, Ohio May 3, 20058, 2006
JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S DISCUSSION ANDANALYSIS OF ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also provides generation services to those customers electing to retain JCP&L as their power supplier.
Restatements As further discussed in Note 15 to the Consolidated Financial Statements, JCP&L has restructuredrestated its electric ratesconsolidated financial statements for the three months ended March 31, 2005. The revisions are the result of a tax audit from the State of New Jersey, in unbundled service charges and transition cost recovery charges.which JCP&L continues to deliver power to homes and businesses through its existing distribution system.became aware that the New Jersey Transitional Energy Facilities Assessment is not an allowable deduction for state income tax purposes.
Results of Operations
Earnings on common stock in the first quarter of 20052006 increased to $14$33.6 million from $13$13.3 million in 2004,2005, principally due to higher operating revenues and lower other operating costs, partially offset by increases in other operating, purchased power costs and regulatory asset amortization.income taxes.
Operating Revenues
Operating revenues increased $31$46.7 million or 6.2%8.8% in the first quarter of 20052006 compared with 2004. Thethe same period of 2005 due to higher revenues primarily resulted from increases in retail electric generation, sales of $18 milliondistribution and distribution revenues of $12 million partially offset by a $4 million decline in wholesale revenues.
The higher Retail generation revenues from generation salesincreased by $37.8 million in the first quarter of 2006 as compared to residential and commercial customersthe previous year in all customer classes (residential - $14$14.9 million, commercial - $21.0 million and commercialindustrial - $9$1.7 million). The increases were due to higher unit prices resulting from the BGS auction effective in May 2005 and increases in sales volume (residential(commercial - 13.2%6.8% and commercialindustrial - 9.2%3.3%) and higher unit prices discussed below.. The sales volume increase wasincreases were primarily due to lower customer shopping. Generation provided by alternative suppliers as a percent of total sales delivered in JCP&L’s service area decreased by 12.16.0 and 3.72.7 percentage points for residentialcommercial and commercialindustrial customers, respectively. A $5Residential KWH generation sales declined by 4.2% from the previous year, reflecting unseasonably mild weather in the first quarter of 2006 (heating degree days were 16.5% lower than in the first quarter of 2005). Wholesale sales revenues increased $1.8 million decrease in industrial sales reflected the effect of increased customer shopping which resulted in a 33.3%primarily due to higher market prices -- wholesale KWH sales decrease.were virtually unchanged from the first quarter of 2005.
JCP&L's BGS obligation has been transferred to external parties as a result of an NJBPU auction process that extended the termination of JCP&L's BGS obligation through May 2005 (see Outlook - Regulatory Matters). The higher unit prices resulted from the BGS auction. The increased total retail generation KWH sales reduced energy available for sale in the wholesale market which resulted in lower wholesale sales revenues of $4 million (15.4% KWH sales decrease).
The increase in distribution revenues in all customer sectors of $12$5.3 million in the first quarter of 20052006 compared to the first quartersame period of 20042005 was primarily due to higher composite unit prices.prices resulting from a distribution rate increase pursuant to the stipulated settlements approved by the NJBPU on May 25, 2005. The 3.9% commercial sector KWH sales increaseeffect of the increased prices was partially offset by minor declines in both the residential and industrial sectors.lower distribution KWH sales.
Changes in KWH sales by customer class in the first quarter of 2006 compared to the same period of 2005 are summarized in the following table:
Changes in KWH Sales | | | | Increase (Decrease) | | | | | Electric Generation: | | | | | Retail | | | 0.5 | % | | | Wholesale | | | 0.1 | % | | Total Electric Generation Sales | | | 0.4 | % | | | | | | | | Distribution Deliveries: | | | | | | | Residential | | | (4.2 | )% | | | Commercial | | | (1.1 | )% | | | Industrial | | | (7.1 | )% | | Total Distribution Deliveries | | | (3.3 | )% | |
The higher operating revenues also reflected a $2an additional $1.0 million payment received in the first quarter of 2006 as compared to the first quarter of 2005 under a contract provision associated with the prior sale of TMI Unit 1. Under the contract, additional payments are received if subsequent energy prices rise above specified levels.levels, which occurred. This payment is credited to JCP&L’s customers, resulting in no net earnings effect.impact.
Changes in kilowatt-hour sales by customer class in the first quarter of 2005 compared to the first quarter of 2004 are summarized in the following table:
| | | | Changes in Kilowatt-hour Sales
| | 2005
| | | | | | Increase (Decrease)
| | | | Electric Generation: | | | | Retail
| | | 8.4 | % | Wholesale
| | | (15.4 | )% | Total Electric Generation Sales
| | | 2.3
| %
| | | | | | Distribution Deliveries: | | | | | Residential
| | | (0.5 | )% | Commercial
| | | 3.9 | % | Industrial
| | | (0.1 | )% | Total Distribution Deliveries
| | | 1.4
| %
|
Operating Expenses and Taxes
Total operating expenses and taxes increased $29by $29.5 million in the first quarter of 20052006 compared to the first quarter of 2005. The following table presents changes from the prior year.year by expense category:
Operating Expenses and Taxes - Changes (In millions) | | | | Increase (Decrease) | | | | | Purchased power costs | | $ | 38.5 | | | Other operating costs | | | (18.0 | ) | | Provision for depreciation | | | 0.4 | | | Amortization of regulatory assets | | | (1.6 | ) | | General taxes | | | 0.8 | | | Income taxes | | | 9.4 | | Total operating expenses and taxes | | $ | 29.5 | |
Purchased power costs increased $6$38.5 million in the first quarter of 20052006 compared to 2004.the same period of 2005. The higher purchased power costsincrease reflected higher KWH purchased due to increased retailprices from the 2005 BGS auction and a 0.4% increase in total electric generation sales. The increasedecrease of $14$18.0 million in other operating costs in the first quarter of 2005 compared to 20042006 reflected in part the effects of a JCP&L labor strike.strike in 2005. The JCP&L labor strike, which affected approximately 1,300 employees, began on December 8, 2004 and lasted until March 15, 2005.
Amortization As a result of regulatory assetssettling the strike later in 2005, associated company billings for work done on behalf of JCP&L of $15.4 million was absent in the first quarter of 2006. In addition, professional and contractor services declined by $2.5 million due to additional expenditures incurred in 2005 as a result of the strike. Income tax expense increased $4$9.4 million in the first quarter of 2005. The2006 as compared to the first quarter of 2005 due to higher amortization was caused by an increase in the level of MTC revenue recovery.pre-tax income.
Capital Resources and Liquidity
JCP&L’s cash requirements in 20052006 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with a combination of cash from operations and funds from the capital markets. Thereafter, JCP&L expects to meet its contractual obligations with cash from operations. Changes in Cash Position
As of March 31, 2005,2006, JCP&L had $41,000$103,000 of cash and cash equivalents compared with $162,000$102,000 as of December 31, 2004.2005. The major sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided from operating activities in the first quarter of 20052006 compared with the first quarter of 2004,2005 were as follows:
| | | | Three Months Ended March 31, | | Operating Cash Flows | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | (In millions) | | Cash earnings(1) | | $ | 37 | | $ | 47 | | | $ | 60 | | $ | 37 | | | Working capital and other | | | 60 | | | 75 | | | | (81 | ) | | 60 | | | Total Cash Flows from Operating Activities | | $ | 97 | | $ | 122 | | | | Net Cash provided from (used for) Operating Activities | | | $ | (21 | ) | $ | 97 | |
(1)Cash earnings isare a non-GAAP measure (see reconciliation below).
Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. JCP&L believes that cash earnings isare a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.income: | | | | Three Months Ended | | | | | | March 31 | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | (In millions) | | | Net Income (GAAP) | | $ | 15 | | $ | 13 | | | $ | 34 | | $ | 13 | | | Non-Cash Charges (Credits): | | | | | | | | | | | | | | | Provision for depreciation | | | 20 | | | 19 | | | | 21 | | | 20 | | Amortization of regulatory assets | | | 68 | | | 64 | | | | 67 | | | 68 | | Deferred costs recoverable as regulatory assets | | | (73 | ) | | (38 | ) | | | (62 | ) | | (73 | ) | Deferred income taxes | | | 7 | | | -- | | | | 4 | | | 7 | | Other non-cash expenses | | | -- | | | (11 | ) | | | (4 | ) | | 2 | | | Cash earnings (Non-GAAP) | | $ | 37 | | $ | 47 | | | $ | 60 | | $ | 37 | |
The $10$23 million decreaseincrease in cash earnings is described above and under "Results“Results of Operations".Operations.” The $15$141 million decrease from working capital primarily resulted from a $115 million change in cash collateral from suppliers and changes in prepayments and accounts payable of approximately $15$39 million. In 2005, JCP&L received cash collateral payments from its suppliers and in the first quarter of 2006 returned $109 million each, partially offset by a $13 million change in receivables.back to its suppliers.
Cash Flows From Financing Activities
Net cash used forprovided from financing activities decreased towas $68 million in the first quarter of 2005 from $882006 as compared to net cash used of $68 million in same period of 2004.2005. The decreaseincrease resulted from a $36$97 million decreaseincrease in netnew short-term borrowings and a $44 million reduction in debt redemptions in the first quarter of 2006, partially offset by a $15an additional $5 million increase inof common stock dividendsdividend payments to FirstEnergy.
JCP&L had about $41,000$22 million of cash and temporary investments (which includes short-term notes receivable from associated companies) and approximately $205$278 million of short-term indebtedness as of March 31, 2005.2006. JCP&L has authorization from the SEC, continued by FERC rules adopted as a result of EPACT's repeal of PUHCA, to incur short-term debt up to its charter limit of $1.038 billion$412 million (including the utility money pool). JCP&L will not issue FMB other than as collateral for senior notes, since its senior note indentures prohibitindenture prohibits (subject to certain exceptions) JCP&L from issuing any debt which is senior to the senior notes. As of March 31, 2005,2006, JCP&L had the capability to issue $578$625 million of additional senior notes based upon FMB collateral. As of March 31, 2005,2006, based upon applicable earnings coverage tests and its charter, JCP&L could issue $564 million$1.5 billion of preferred stock (assuming no additional debt was issued).
JCP&L has the ability to borrow from FirstEnergy and its regulated affiliates 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 agreementsagreement must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 20052006 was 2.66%4.58%.
JCP&L’s&L, FirstEnergy, OE, Penn, CEI, TE, Penelec, Met-Ed, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility which expires in June 2010. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. JCP&L's borrowing limit under the facility is $425 million.
Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding letters of credit will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.
The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of March 31, 2006, JCP&L's debt to total capitalization as defined under the revolving credit facility was 27%.
The facility does not contain any provisions that either restrict JCP&L's ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to its credit ratings.
JCP&L's access to the capital markets and the costs of financing are dependent on the ratings of its securities and thethat of FirstEnergy. As of March 31, 2006, JCP&L's and FirstEnergy’s ratings outlook from S&P on all securities of FirstEnergy.was stable. The ratings outlook from the rating agenciesMoody’s and Fitch on all such securities is stable.
On March 18, 2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affect FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings outlook would be revised to positive.
Cash Flows From Investing Activities
Net cash used in investing activities was $30$47 million in the first quarter of 20052006 compared to $34$30 million in the previous year. The $4$17 million decreasechange primarily resulted from a $4$17 million decreaseincrease in property removal costs.additions for distribution system reliability initiatives.
During the last three quarters of 2005,2006, capital requirements for property additions and improvements are expected to be about $150$132.5 million. These cash requirements are expected to be satisfied from a combination of internal cash, funds raised in the long-term debt capital markets and short-term credit arrangements.
JCP&L’s capital spending for the period 2005-20072006-2010 is expected to be about $511$926 million for property additions, of which approximately $178$176 million applies to 2005.2006.
Market Risk Information
JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. Its Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout JCP&L. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.
Commodity Price Risk
JCP&L is exposed to market risk primarily due to fluctuations in electricity, energy transmission and natural gas prices. To manage the volatility relating to these exposures, itJCP&L uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and futures contracts.swaps. The derivatives are used principally for hedging purposes. MostDerivatives that fall within the scope of its non-hedgeSFAS 133 must be recorded at their fair value and marked to market. The majority of JCP&L’s derivative hedging contracts represent non-trading positions that do not qualify for hedge treatmentthe normal purchase and normal sale exception under SFAS 133. As133 and are therefore excluded from the table below. Contracts that are not exempt from such treatment include power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policy Act of March 31, 2005 JCP&L had1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts with a fair valuerelated to energy production during the first quarter of $14 million. A decrease of $1 million2006 is summarized in the value of this asset was recorded as a decrease in a regulatory liability and, therefore, had no impact on net income.following table:
Decrease in the Fair Value of Derivative Contracts | | Non-Hedge | | Hedge | | Total | | | | | (In millions) | | Change in the fair value of commodity derivative contracts: | | | | | | | | | Outstanding net liabilities as of January 1, 2006 | | $ | (1,223 | ) | $ | - | | $ | (1,223 | ) | | New contract value when entered | | | - | | | - | | | - | | | Additions/Changes in value of existing contracts | | | 123 | | | - | | | 123 | | | Change in techniques/assumptions | | | - | | | - | | | - | | | Settled contracts | | | (73 | ) | | - | | | (73 | ) | | | | | | | | | | | | | Net Liabilities - Derivatives Contracts as of March 31, 2006(1) | | $ | (1,173 | ) | $ | - | | $ | (1,173 | ) | | | | | | | | | | | | | Impact of Changes in Commodity Derivative Contracts(2) | | | | | | | | | | | | Income Statement Effects (Pre-Tax) | | $ | (1 | ) | $ | - | | $ | (1 | ) | | Balance Sheet Effects: | | | | | | | | | | | | OCI (Pre-Tax) | | $ | - | | $ | - | | $ | - | | | Regulatory Asset (Net) | | $ | (51 | ) | $ | - | | $ | (51 | ) |
| (1) | These contracts (primarily with NUGs) are offset by a regulatory asset. |
| (2) | Represents the change in value of existing contracts, settled contracts and changes in techniques/ assumptions. |
Derivatives are included on the Consolidated Balance Sheet as of March 31, 2006 as follows:
Balance Sheet Classification | | Non-Hedge | | Hedge | | Total | | | | | (In millions) | | Current- | | | | | | | | | Other Assets | | $ | - | | $ | - | | $ | - | | | Other liabilities | | | (1 | ) | | - | | | (1 | ) | | | | | | | | | | | | | Non-Current- | | | | | | | | | | | | Other Deferred Charges | | | 11 | | | - | | | 11 | | | Other noncurrent liabilities | | | (1,183 | ) | | - | | | (1,183 | ) | Net liabilities | | $ | (1,173 | ) | $ | - | | $ | (1,173 | ) |
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, we relyJCP&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. TheSources of information for the valuation of thecommodity derivative contract atcontracts as of March 31, 2005 uses prices from sources shown2006 are summarized by year in the following table:
Source of Information - Fair Value by Contract Year
| | | 2005 | | 2006 | | 2007 | | 2008 | | Thereafter | | Total | | | 2006(1) | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter | | Total | | | | | (In millions) | | | (In millions) | | | | | | | | | | | | | | | | | | Prices actively quoted (2) | | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | Other external sources(1)(3) | | $ | 3 | | $ | 3 | | $ | -- | | $ | -- | | $ | -- | | $ | 6 | | | | (235 | ) | $ | (266 | ) | | (231 | ) | | - | | | - | | - | | | (732 | ) | | Prices based on models | | | -- | | | -- | | | 2 | | | 2 | | | 4 | | | 8 | | | | - | | | - | | | - | | | (156 | ) | | (128 | ) | | (157 | ) | | (441 | ) | | | | | | | | | | | | | | | | | | Total(2) | | $ | 3 | | $ | 3 | | $ | 2 | | $ | 2 | | $ | 4 | | $ | 14 | | | Total(4) | | | $ | (235 | ) | $ | (266 | ) | $ | (231 | ) | $ | (156 | ) | $ | (128 | ) | $ | (157 | ) | $ | (1,173 | ) |
(1)For the last three quarters of 2006. (2)Exchange traded. (3) Broker quote sheets. (2)(4) Includes $14$1,173 million from an embedded option that isin non-hedge commodity derivative contracts, which are offset by a regulatory liability and does not affect earnings.asset.
JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity position.positions. A hypothetical 10% adverse shift in quoted market prices in the near term on both our trading and non-trading derivative instruments would not have had a material effect on itsJCP&L’s consolidated financial position or cash flows as of March 31, 2005.2006. JCP&L estimates that if energy commodity prices experienced an adverse 10% change, net income for the next twelve months would not change, as the prices for all commodity positions are already above the contract price caps.
Equity Price Risk Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $78$88 million and $80$84 million at March 31, 20052006 and December 31, 2004,2005, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $8a $9 million reduction in fair value as of March 31, 2005.2006.
OutlookRegulatory Matters
The electric industry continues to transition to a more competitive environment and all ot JCP&L's customers can select alternative energy suppliers. JCP&L 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. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
Regulatory Matters
Beginning in 1999, all of JCP&L's customers had a choice for electric generation suppliers. JCP&L's customer rates were restructured into unbundled service charges and additional non-bypassable charges to recover stranded costs.
Regulatory assets are costs which have been authorized by the NJBPU and the FERC for recovery from customers in the future periods and, withoutor for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income whenas incurred. All of JCP&L's&L’s regulatory assets are expected to continue to be recovered under the provisions of the regulatory proceedings discussed below. JCP&L’s regulatory assets totaled $2.2 billion as of March 31, 20052006 and December 31, 20042005.
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 NUGC rates and market sales of NUG energy and capacity. As of March 31, 2006, the accumulated deferred cost balance totaled approximately $558 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval to securitize the July 31, 2003 deferred balance. On December 2, 2005, JCP&L filed a request for recovery of $165 million of actual above-market NUG costs incurred from August 1, 2003 through October 31, 2005 and forecasted above-market NUG costs for November and December 2005. On February 1, 2006, the NJBPU selected Bear Stearns as the financial advisor. Meetings with the NJBPU Staff and the DRA were $2.3 billionheld during March and $2.2 billion, respectively.April and additional discovery conducted. The DRA filed comments on April 6, 2006, arguing that the proposed securitization does not produce customer savings. JCP&L submitted reply comments on April 10, 2006. On February 23, 2006, JCP&L filed updated data reflecting actual amounts through December 31, 2005 of $154 million of cost incurred since July 31, 2003. The filing also includes a request for recovery of $49 million for above-market NUG costs incurred prior to August 1, 2003, to the extent those costs are not recoverable through securitization. On March 29, 2006, a pre-hearing conference was held with the presiding ALJ. A schedule for the proceeding was established including a discovery period and evidentiary hearings scheduled for September 2006. An NJBPU Decision and Order approving a Phase II Stipulation of Settlement and resolving the Motion for Reconsideration of the Phase I Order was issued on May 31, 2005. The Phase II Settlement includes a performance standard pilot program with potential penalties of up to 0.25% of equity return. The Order requires that JCP&L file quarterly reliability reports (CAIDI and SAIFI information related to the performance pilot program) through December 2006 and updates to reliability related project expenditures until all projects are completed. The first quarterly report was submitted to NJBPU on August 16, 2005. The second quarterly report was submitted on November 22, 2005. The third quarterly report as of December 31, 2005 was submitted on March 28, 2006. As of December 31, 2005 there were no performance penalties issued by the NJBPU.
JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to an NJBPU order for the period June 1, 2005 through May 31, 2006.
The July 2003 NJBPU decision on JCP&L's base electric rate proceeding ordered a Phase II proceeding be conducted to review whether JCP&L is in compliance with current service reliability and quality standards. The NJBPU also ordered that any expenditures and projects undertaken by JCP&L to increase its system's reliability be reviewed as part ofapproving the Phase II proceeding, to determine their prudence and reasonableness for rate recovery. 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. On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 millionBGS procurement proposal for the recovery of system reliability costs and a 9.75% returnperiod beginning June 1, 2006 was issued on equity. The filing also requests an increase to the MTC deferred balance recovery of approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004, andOctober 12, 2005. JCP&L submitted rebuttal testimonya compliance filing on January 4,October 26, 2005, which was approved on November 10, 2005. The Ratepayer Advocate surrebuttal testimonywritten Order was submitted Februarydated December 8, 2005. DiscoveryThe auction took place in February 2006. On February 9, 2006, the NJBPU approved the auction results and settlement conferences are ongoing.a written order was signed on February 23, 2006. The JCP&L tariff compliance filing was approved on March 29, 2006. New BGS rates become effective June 1, 2006.
In a reaction to the higher closing prices of the 2006 BGS fixed rate auction, the NJBPU, on March 16, 2006, initiated a generic proceeding to evaluate the auction process and potential options for the future. On April 6, 2006, initial comments were submitted. A public meeting was held on April 21, 2006 and a legislative-type hearing was held on April 28, 2006. Final comments were due on May 4, 2006. An NJBPU decision is anticipated in June 2006.
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 customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. 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. The Ratepayer AdvocateDRA filed comments on February 28, 2005.2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further proceedings has not yet been set.
As a result of outages experienced in JCP&L's service area in 2002 and 2003,On August 1, 2005, the NJBPU had implemented reviewsestablished a proceeding to determine whether additional ratepayer protections are required at the state level in light of the recent repeal of PUHCA under the EPACT. An NJBPU proposed rulemaking to address the issues was published in the NJ Register on December 19, 2005. The proposal would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. A public hearing was held February 7, 2006 and comments were submitted to the NJBPU. The NJBPU Staff issued a draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. Comments and reply comments are due by May 22 and May 31, 2006, respectively. JCP&L's&L is not able to predict the outcome of this proceeding at this time.
On December 21, 2005, the NJBPU initiated a generic proceeding and requested comments in order to formulate an appropriate regulatory treatment for investment tax credits related to generation assets divested by New Jersey’s four electric utility companies. Comments were filed by the utilities and by the DRA.
On November 18, 2004, the FERC issued an order eliminating the regional through and out rates (RTOR) for transmission service reliability.between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within the MISO and PJM to submit compliance filings containing a mechanism - the Seams Elimination Cost Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be involved in the FERC hearings concerning the calculation and imposition of the SECA charges. The hearing began on May 1, 2006. The FERC has ordered the Presiding Judge to issue an initial decision by August 11, 2006.
On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order. On March 29, 2004, the NJBPU adopted20, 2006 a Memorandum of Understanding (MOU) that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L's ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability and the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit). A Final Ordersettlement was filed with FERC in the Focused Audit docket wasformula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued byan order approving this settlement on April 19, 2006. If the NJBPUFERC accepts AEP's proposal, significant additional transmission revenues would be imposed on July 23, 2004. On February 11, 2005, JCP&L, met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOUMet-Ed, Penelec, and Stipulation.other transmission zones within PJM.
See Note 1311 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.
Employee Matters
On March 15, 2005, members of the International Brotherhood of Electrical Workers System Council U-3 ratified a new four-year contract with JCP&L. Ratification of the contract resolved issues surrounding health care and work rules, and ended a 14-week strike against JCP&L by the Council’s members.
Environmental Matters
JCP&L accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs 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.
JCP&L has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, CompensationResponsive, Comprehension 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 held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2005,2006, based on estimates of the total costs of cleanup, JCP&L's&L’s proportionate responsibility for such costs and the financial ability of other nonaffiliatedunaffiliated 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 Other Noncurrent Liabilities areTotal liabilities of approximately $47.3 million have been accrued liabilities aggregating approximately $47 million as ofthrough March 31, 2005.2006.
See Note 10(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.
Other Legal Proceedings
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to JCP&L's normal business operations pending against JCP&L. The most significantother material items not otherwise discussed below are described below.
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 of New Jersey’s 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 product 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 appealedNote 10(C) 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 has filed a motion for summary judgment. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of March 31, 2005.consolidated financial statements.
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. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,concluded, 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 real-time 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 contained 46 "recommendations“recommendations to prevent or minimize the scope of future blackouts."” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in process,new or material upgrades to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother applicable government agencies and reliability coordinators may, however, 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 asFinally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of March 31, 2005 forcontrol room operators before determining the next steps, if any, expenditures in excess of those actually incurred through that date.
One complaint was filed on August 25, 2004 against FirstEnergy in the New Yorkproceeding.
FirstEnergy was named in a complaint filed in Michigan State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages asCourt by an individual who is not a result of the August 14, 2003 power outages. None of the plaintiffs are customerscustomer of any FirstEnergy affiliate.company. A responsive pleading to this matter has been filed. FirstEnergy filedwas also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy are based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. No FirstEnergy entity serves any customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss withdismiss. It is uncertain whether the Court on October 22, 2004.plaintiff will appeal. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thusof potential liability has not been determined.undertaken in either of these matters. FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular,Although unable to predict the impact of these proceedings, 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.operations and cash flows.
JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, the federal court granted a Union motion to dismiss JCP&L's appeal of the award as premature. JCP&L will file its appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.
The other material items not otherwise discussed above are described in Note 10(C) to the consolidated financial statements.
New Accounting Standards and Interpretations
FIN 47,“AccountingEITF Issue 04-13, "Accounting for Conditional Asset Retirement Obligations - an interpretationPurchases and Sales of FASB Statement No. 143”Inventory with the Same Counterparty"
On March 30,In September 2005, the FASB issued this interpretation to clarifyEITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the scopesame counterparty should be combined and timingconsidered as a single arrangement for purposes of liability recognitionapplying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for theat fair valuevalue. Although electric power is not capable of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances wherebeing held in inventory, there is insufficient information to estimate the liability, the obligation is to be recognizedno substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, JCP&L will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed.interim or annual periods beginning after March 15, 2006. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. FirstEnergy is currently evaluating the effect this standardEITF issue will not have a material impact on theJCP&L's financial statements.results.
EITF IssueSFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 03-1, "The Meaning133 and 140”
In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of Other-Than-Temporary ImpairmentFinancial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. JCP&L is currently evaluating the impact of this Statement on its Application to Certain Investments"financial statements.
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.
METROPOLITAN EDISON COMPANY | METROPOLITAN EDISON COMPANY | | METROPOLITAN EDISON COMPANY | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | (Unaudited) | (Unaudited) | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | Three Months Ended | | | | | | | March 31, | | | March 31, | | | | | | | | | | | | 2006 | | 2005 | | | | | | | 2005 | | 2004 | | | (In thousands) | | | | | | | | | | | | | | | | | | | | | (In thousands) | | | | | | | | | | | | | OPERATING REVENUES | | | | | $ | 295,781 | | $ | 260,898 | | | $ | 311,213 | | $ | 295,781 | | | | | | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | | Fuel and purchased power | | | | | 150,133 | | 143,456 | | | | Purchased power | | | | 159,887 | | 150,133 | | | Other operating costs | | | | | 58,430 | | 33,048 | | | | 61,079 | | 58,430 | | | Provision for depreciation | | | | | 11,521 | | 9,898 | | | | 10,905 | | 11,521 | | | Amortization of regulatory assets | | | | | 28,621 | | 25,497 | | | | 30,048 | | 28,621 | | | General taxes | | | | | 19,272 | | 17,736 | | | | 20,621 | | 19,272 | | | Income taxes | | | | | | 6,732 | | | 7,980 | | | | 6,336 | | | 6,732 | | | Total operating expenses and taxes | | | | | | 274,709 | | | 237,615 | | | | 288,876 | | | 274,709 | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | | | 21,072 | | 23,283 | | | | 22,337 | | | 21,072 | | | | | | | | | | | | | | | | | | OTHER INCOME (net of income taxes) | | | | | 6,449 | | 5,526 | | | | 6,494 | | | 6,449 | | | | | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | | | | | Interest on long-term debt | | | | | 9,560 | | 10,147 | | | | 8,717 | | 9,560 | | | Allowance for borrowed funds used during construction | | | | | (178 | ) | | (71 | ) | | | (267 | ) | | (178 | ) | | Other interest expense | | | | | | 1,663 | | | 689 | | | | 2,467 | | | 1,663 | | | Net interest charges | | | | | | 11,045 | | | 10,765 | | | | 10,917 | | | 11,045 | | | | | | | | | | | | | | | | | | NET INCOME | | | | | $ | 16,476 | | $ | 18,044 | | | | 17,914 | | 16,476 | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | Unrealized gain (loss) on derivative hedges | | | | | 84 | | (3,260 | ) | | | Unrealized gain on available for sale securities | | | | | | -- | | | 22 | | | | Other comprehensive income (loss) | | | | | 84 | | (3,238 | ) | | | Income tax related to other comprehensive income | | | | | | (35 | ) | | (9 | ) | | | Other comprehensive income (loss), net of tax | | | | | | 49 | | | (3,247 | ) | | OTHER COMPREHENSIVE INCOME: | | | | | | | | | Unrealized gain on derivative hedges | | | | 84 | | 84 | | | Income tax expense related to other comprehensive income | | | | 35 | | | 35 | | | Other comprehensive income, net of tax | | | | 49 | | | 49 | | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | | | | $ | 16,525 | | $ | 14,797 | | | $ | 17,963 | | $ | 16,525 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral partof these statements. | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are | | | | an integral part of these statements. | | an integral part of these statements. | |
METROPOLITAN EDISON COMPANY | METROPOLITAN EDISON COMPANY | | METROPOLITAN EDISON COMPANY | | | | | | | | | | | | | CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | (Unaudited) | | (Unaudited) | | | | | | | | | | | | | | | | | | March 31, | | December 31, | | | March 31, | | December 31, | | | | | | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | | | (In thousands) | | | (In thousands) | | ASSETS | | | | | | | | | | | | | | UTILITY PLANT: | | | | | | | | | | | | | | | In service | | | | | $ | 1,796,340 | | $ | 1,800,569 | | | $ | 1,869,720 | | $ | 1,856,425 | | | Less - Accumulated provision for depreciation | | | | | | 697,927 | | | 709,895 | | | | 721,156 | | | 721,566 | | | | | | | | 1,098,413 | | 1,090,674 | | | | 1,148,564 | | 1,134,859 | | | Construction work in progress | | | | | | 19,714 | | | 21,735 | | | | 21,739 | | | 20,437 | | | | | | | | | 1,118,127 | | | 1,112,409 | | | | 1,170,303 | | | 1,155,296 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | | | | | Nuclear plant decommissioning trusts | | | | | 216,061 | | 216,951 | | | | 242,165 | | 234,854 | | | Long-term notes receivable from associated companies | | | | | 10,775 | | 10,453 | | | | Other | | | | | | 28,899 | | | 34,767 | | | | 24,159 | | | 29,678 | | | | | | | | | 255,735 | | | 262,171 | | | | 266,324 | | | 264,532 | | CURRENT ASSETS: | | | | | | | | | | | | | | | | Cash and cash equivalents | | | | | 120 | | 120 | | | | 120 | | 120 | | | Notes receivable from associated companies | | | | | 21,570 | | 18,769 | | | | 30,012 | | 27,867 | | | Receivables- | | | | | | | | | | | | | | | | Customers (less accumulated provisions of $4,418,000 and $4,578,000, | | | | | | | | | | | Customers (less accumulated provisions of $4,356,000 and $4,352,000, | | | | | | | | | respectively, for uncollectible accounts) | | | | | 126,303 | | 119,858 | | | | 126,917 | | 129,854 | | | Associated companies | | | | | 42,649 | | 118,245 | | | | 13,649 | | 37,267 | | | Other (less accumulated provision of $29,000 for uncollectible accounts in 2005) | | | | | 14,932 | | 15,493 | | | | Other | | | | 7,506 | | 8,780 | | | Prepayments and other | | | | | | 45,192 | | | 11,057 | | | | 47,725 | | | 7,912 | | | | | | | | | 250,766 | | | 283,542 | | | | 225,929 | | | 211,800 | | DEFERRED CHARGES: | | | | | | | | | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | | | 867,769 | | 869,585 | | | | 860,592 | | 864,438 | | | Regulatory assets | | | | | 750,244 | | 693,133 | | | | 308,289 | | 309,556 | | | Prepaid pension costs | | | | 90,738 | | 89,005 | | | Other | | | | | | 24,140 | | | 24,438 | | | | 22,831 | | | 23,060 | | | | | | | | | 1,642,153 | | | 1,587,156 | | | | 1,282,450 | | | 1,286,059 | | | | | | | | $ | 3,266,781 | | $ | 3,245,278 | | | $ | 2,945,006 | | $ | 2,917,687 | | CAPITALIZATION AND LIABILITIES | | | | | | | | | | | | | | | CAPITALIZATION: | | | | | | | | | | | | | | | | Common stockholder's equity- | | | | | | | | | | | | | | | | Common stock, without par value, authorized 900,000 shares - | | | | | | | | | | | 859,500 shares outstanding | | | | | $ | 1,289,943 | | $ | 1,289,943 | | | | Common stock, without par value, authorized 900,000 shares- | | | | | | | | | 859,000 shares outstanding | | | $ | 1,283,268 | | $ | 1,287,093 | | | Accumulated other comprehensive loss | | | | | (43,441 | ) | | (43,490 | ) | | | (1,520 | ) | | (1,569 | ) | | Retained earnings | | | | | | 46,442 | | | 38,966 | | | | 48,489 | | | 30,575 | | | Total common stockholder's equity | | | | | 1,292,944 | | 1,285,419 | | | | 1,330,237 | | 1,316,099 | | | Long-term debt and other long-term obligations | | | | | | 694,214 | | | 701,736 | | | | 591,918 | | | 591,888 | | | | | | | | | 1,987,158 | | | 1,987,155 | | | | 1,922,155 | | | 1,907,987 | | CURRENT LIABILITIES: | | | | | | | | | | | | | | | | Currently payable long-term debt | | | | | 37,395 | | 30,435 | | | | 100,000 | | 100,000 | | | Short-term borrowings- | | | | | | | | | | | | | | | | Associated companies | | | | | 108,677 | | 80,090 | | | | 82,312 | | 140,240 | | | Other | | | | 75,000 | | - | | | Accounts payable- | | | | | | | | | | | | | | | | Associated companies | | | | | 30,959 | | 88,879 | | | | 14,475 | | 37,220 | | | Other | | | | | 34,426 | | 26,097 | | | | 51,412 | | 27,507 | | | Accrued taxes | | | | | 2,286 | | 11,957 | | | | 11,831 | | 17,911 | | | Accrued interest | | | | | 10,445 | | 11,618 | | | | 9,329 | | 9,438 | | | Other | | | | | | 17,741 | | | 23,076 | | | | 20,362 | | | 24,274 | | | | | | | | | 241,929 | | | 272,152 | | | | 364,721 | | | 356,590 | | NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | Accumulated deferred income taxes | | | | | 314,193 | | 305,389 | | | | 348,849 | | 344,929 | | | Accumulated deferred investment tax credits | | | | | 10,662 | | 10,868 | | | | 9,843 | | 10,043 | | | Power purchase contract loss liability | | | | | 393,825 | | 349,980 | | | | Nuclear fuel disposal costs | | | | | 38,631 | | 38,408 | | | | 39,979 | | 39,567 | | | Asset retirement obligation | | | | | 134,964 | | 132,887 | | | | 144,239 | | 142,020 | | | Retirement benefits | | | | | 80,571 | | 82,218 | | | | 57,517 | | 57,809 | | | Other | | | | | | 64,848 | | | 66,221 | | | | 57,703 | | | 58,742 | | | | | | | | | 1,037,694 | | | 985,971 | | | | 658,130 | | | 653,110 | | COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | | | | | $ | 3,266,781 | | $ | 3,245,278 | | | $ | 2,945,006 | | $ | 2,917,687 | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of thesebalance sheets. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these | | balance sheets. | | balance sheets. |
METROPOLITAN EDISON COMPANY | METROPOLITAN EDISON COMPANY | | METROPOLITAN EDISON COMPANY | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | CONSOLIDATED STATEMENTS OF CASH FLOWS | | CONSOLIDATED STATEMENTS OF CASH FLOWS | (Unaudited) | (Unaudited) | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | | March 31, | | | | | | | | | | | | | Three Months Ended | | | | | | | 2005 | | 2004 | | | March 31, | | | | | | | | | | | | 2006 | | 2005 | | | | | | | (In thousands) | | | (In thousands) | | | | | | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | | | | Net income | | | | | $ | 16,476 | | $ | 18,044 | | | $ | 17,914 | | $ | 16,476 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | | | | | | | Provision for depreciation | | | | | 11,521 | | 9,898 | | | | 10,905 | | 11,521 | | | Amortization of regulatory assets | | | | | 28,621 | | 25,497 | | | | 30,048 | | 28,621 | | | Deferred costs recoverable as regulatory assets | | | | | (16,441 | ) | | (16,792 | ) | | | (22,818 | ) | | (25,271 | ) | | Deferred income taxes and investment tax credits, net | | | | | (11 | ) | | 2,433 | | | | 1,704 | | (11 | ) | | Accrued retirement benefit obligation | | | | | (1,647 | ) | | 1,074 | | | | Accrued compensation, net | | | | | (1,723 | ) | | (634 | ) | | | Decrease (Increase) in operating assets: | | | | | | | | | | | Accrued compensation and retirement benefits | | | | (3,912 | ) | | (3,370 | ) | | Commodity derivative transactions, net | | | | (2,148 | ) | | - | | | Decrease (increase) in operating assets: | | | | | | | | | Receivables | | | | | 69,712 | | 5,767 | | | | 27,829 | | 69,712 | | | Materials and supplies | | | | | (18 | ) | | 18 | | | | Prepayments and other current assets | | | | | (34,117 | ) | | (36,618 | ) | | | (37,665 | ) | | (34,135 | ) | | Increase (Decrease) in operating liabilities: | | | | | | | | | | | Increase (decrease) in operating liabilities: | | | | | | | | | Accounts payable | | | | | (49,591 | ) | | 6,848 | | | | 1,160 | | (49,591 | ) | | Accrued taxes | | | | | (9,671 | ) | | (1,546 | ) | | | (6,080 | ) | | (9,671 | ) | | Accrued interest | | | | | (1,173 | ) | | (4,465 | ) | | | (109 | ) | | (1,173 | ) | | Other | | | | | | (9,134 | ) | | (8,265 | ) | | | (4,649 | ) | | (304 | ) | | Net cash provided from operating activities | | | | | | 2,804 | | | 1,259 | | | | 12,179 | | | 2,804 | | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | New Financing- | | | | | | | | | | | | | | | | Long-term debt | | | | | -- | | 247,607 | | | | Short-term borrowings, net | | | | | 28,587 | | -- | | | | 17,065 | | 28,587 | | | Redemptions and Repayments- | | | | | | | | | | | | | | | | Long-term debt | | | | | (435 | ) | | (50,435 | ) | | | - | | (435 | ) | | Short-term borrowings, net | | | | | -- | | (65,335 | ) | | | Dividend Payments- | | | | | | | | | | | | | | | | Common stock | | | | | | (9,000 | ) | | (5,000 | ) | | | - | | | (9,000 | ) | | Net cash provided from financing activities | | | | | | 19,152 | | | 126,837 | | | | 17,065 | | | 19,152 | | | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | Property additions | | | | | (16,199 | ) | | (8,962 | ) | | | (25,277 | ) | | (16,199 | ) | | Contributions to nuclear decommissioning trusts | | | | | (2,371 | ) | | (2,371 | ) | | | Proceeds from nuclear decommissioning trust fund sales | | | | 42,061 | | 22,667 | | | Investments in nuclear decommissioning trust funds | | | | (44,432 | ) | | (25,038 | ) | | Loans to associated companies, net | | | | | (3,150 | ) | | (116,802 | ) | | | (2,145 | ) | | (3,150 | ) | | Other | | | | | | (236 | ) | | 38 | | | | 549 | | | (236 | ) | | Net cash used for investing activities | | | | | | (21,956 | ) | | (128,097 | ) | | | (29,244 | ) | | (21,956 | ) | | | | | | | | | | | | | | | | | | Net increase (decrease) in cash and cash equivalents | | | | | -- | | (1 | ) | | | Net change in cash and cash equivalents | | | | - | | - | | | Cash and cash equivalents at beginning of period | | | | | | 120 | | | 121 | | | | 120 | | | 120 | | | Cash and cash equivalents at end of period | | | | | $ | 120 | | $ | 120 | | | $ | 120 | | $ | 120 | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are anintegral part of these statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an | | integral part of these statements. | | integral part of these statements. |
Report of Independent Registered Public Accounting Firm
To the StockholdersStockholder and Board of Directors of Metropolitan Edison Company:
We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of March 31, 2005,2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 20052006 and 2004.2005. 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 as of December 31, 2004,2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004;(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 and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 2(G) 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 69 to those consolidated financial statements) dated March 7, 2005,February 27, 2006, we expressed an unqualified opinions thereon. Theopinion on those consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein.statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004,2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP Cleveland, Ohio May 3, 20058, 2006
METROPOLITAN EDISON COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service 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. Met-Ed continues to deliver power to homes and businesses through its existing distribution system.
Results of Operations
Net incomeIncome in the first quarter of 2005 decreased2006 increased to $16$18 million from $18$16 million in the first quarter of 2004. The decrease2005. This increase was primarily due to higher operating revenues and lower depreciation expense, and was partially offset by increases in purchased power costs, other operating costs, amortization of regulatory assets other operating costs and general taxes. The decrease was partially offset by increased operating revenues.
Operating revenues increased by $35$15 million, or 13.4%5.2% in the first quarter of 20052006 compared with the first quarter of 2004. Thesame period in 2005 primarily due to higher revenues primarily resulted from increases of retail generation electric sales of $15 millionrevenues, transmission revenues and other operating revenues, partially offset by lower distribution revenues. Retail generation revenues of $6 million. The higher generation sales revenuesincreased in all customer sectors reflected the effect of a 10.1% KWH sales increase andby $12 million principally due to higher composite unit prices.prices and a 12.1% increase in industrial KWH sales. The industrial sales volume increase resulted from lower customer shopping due to customers returning to Met-Ed as theirreduced generation supplier.service provided by alternative suppliers. Sales by alternative suppliers as a percent of total industrial sales delivered in Met-Ed’sMed-Ed's franchise area decreased by 18.2, 1.4 and 0.113.7 percentage points in the industrial, commercial and residential sectors, respectively.
Revenues from distribution throughput increased by $6 million. The higher revenues were due to higher KWH deliveries (3.7% increase) and unit prices in the first quarter of 2005 as compared to the same period of 2004. Also contributing to the higher operating revenues was a $102006.
Revenues from distribution throughput decreased by $2 million, increase due to Met-Ed’s assumption of transmission revenues (PJM congestion credit and FTR/ARR) from FESprimarily due to a change2.4% decrease in KWH deliveries, reflecting the power supply agreementeffect of milder temperatures in the second quarter of 2004,2006 compared with 2005, as demonstrated by a 16.4% decrease in heating degree days, partially offset by slightly higher composite unit prices. Transmission revenues increased by $3 million primarily due to higher transmission prices, which also resulted in higher transmission expenses as discussed below. In addition, the higherOther operating revenues also increased due to a $2 million increase in the first quarter of 2006, compared with the first quarter of 2005, included a $4 millionin the payment received under a contract provision associated with the prior sale of TMI Unit 1. Under the contract, additional payments are received if subsequent energy prices rise above specified levels.levels, which occurred. This payment is credited to Met-Ed’s customers, resulting in no net earnings effect.
Changes in KWH deliveriessales by customer class in the first quarter of 20052006 compared to the first quarter 2004same period of 2005 are summarized in the following table:
Changes in KWH Sales | | | | Increase (Decrease) | | | | | Retail Electric Generation: | | | | | Residential | | | (2.5 | %) | | | | Commercial | | | 0.1 | % | | | | Industrial | | | 12.1 | % | | | ResidentialTotal Retail Electric Generation Sales
| | | 2.22.0 | % | | | Commercial
Distribution Deliveries: | | | 5.4 | % | Industrial
| | | 3.9 | | Residential | | | (2.7 | %) | | | | Commercial | | | (0.8 | %) | | | | Industrial | | | (3.6 | %) | | | Total KWHDistribution Deliveries | | | 3.7
(2.4 | % ) | | |
Operating Expenses and Taxes
Total operating expenses and taxes increased by $37$14 million, or 5.2% in the first quarter of 2006 compared to the first quarter of 2005. The following table presents changes from the prior year by expense category:
Operating Expenses and Taxes - Changes (In millions) | | | | Increase (Decrease) | | | | | Purchased power costs | | $ | 10 | | | Other operating costs | | | 3 | | | Provision for depreciation | | | (1 | ) | | Amortization of regulatory assets | | | 1 | | | General taxes | | | 1 | | | Income taxes | | | - | | Total operating expenses and taxes | | $ | 14 | |
Purchased power costs increased by $10 million in the first quarter of 2005 from2006 as compared with the first quartersame period of 2004. Purchased power costs increased in 2005 primarily due2005. The increase was mainly attributable to an $18 million increase in two-party power purchases and a $2 million increase in NUG contract purchases, partially offset by a $14 million reduction in power purchased from FES. The net2.1% increase in KWH purchases was attributable to the increase inmeet higher retail generation sales.
demand requirements. The effect of the increased power purchases was partially offset by lower composite unit prices. NUG contract purchases also increased by $2 million. Other operating costs increased in the first quarter of 20052006 primarily due to $27 million higher PJM ancillary transmission expenses, congestion charges, and FTR/ARR expenses. Thewhich increased as a result of the higher transmission expense increase resulted from Met-Ed’s assumption of PLR transmission related transactionsprices discussed above. Other operating costs also increased due to higher storm-related and vegetation management costs.
Depreciation expenses increased due to higher estimated costs to decommission the Saxton nuclear plant and depreciation expense on property purchased from FESC in late 2004. Amortization of regulatory assets increased primarilyprincipally due to increased amortizationa higher level of regulatory assets being recovered through CTC rates,revenue recovery, partially offset by lower amortization related to above market NUGof non-NUG stranded costs.
General taxes increased by $2$1 million in the first quarter of 20052006 primarily due to higher gross receipt taxes.
Capital Resources and Liquidity
Met-Ed’s cash requirements in 2005 and thereafter,2006 for operating expenses, construction expenditures and scheduled debt maturities, are expected to be met with a combination of cash from operations and funds from the capital markets.short-term credit arrangements.
Changes in Cash Position
As of March 31, 20052006 and December 31, 2004,2005, Met-Ed had $120,000 of cash and cash equivalents.
Cash Flows From Operating Activities
Cash provided from operating activities in the first quarter of 20052006 and 20042005 were as follows:
| | | | Three Months Ended March 31, | | Operating Cash Flows | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | (In millions) | | Cash earnings(1) | | $ | 37 | | $ | 39 | | | $ | 32 | | $ | 28 | | | Working capital and other | | | (34 | ) | | (38 | ) | | | (20 | ) | | (25 | ) | | | | | | | | | | | | | | | | | | Total Cash Flows from Operating Activities | | $ | 3 | | $ | 1 | | | | Net cash provided from operating activities | | | $ | 12 | | $ | 3 | |
(1) Cash earnings is a non-GAAP measure (see reconciliation below).
Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. Met-Ed believes that cash earnings isare a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. | | | Three Months Ended | | | | | March 31, | | Reconciliation of Cash Earnings | | 2006 | | 2005 | | | | | (In millions) | | | Net Income (GAAP) | | $ | 18 | | $ | 16 | | | Non-Cash Charges (Credits): | | | | | | | | | Provision for depreciation | | | 11 | | | 12 | | | Amortization of regulatory assets | | | 30 | | | 29 | | | Deferred costs recoverable as regulatory assets | | | (23 | ) | | (25 | ) | | Deferred income taxes and investment tax credits, net | | | 2 | | | - | | | Commodity derivative transactions, net | | | (2 | ) | | - | | | Other non-cash expenses | | | (4 | ) | | (4 | ) | | Cash earnings (Non-GAAP) | | $ | 32 | | $ | 28 | |
| | | Three Months Ended | | | | | March 31, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | | | | (In millions) | | | | | | | | | | Net Income (GAAP) | | $ | 16 | | $ | 18 | | | Non-Cash Charges (Credits): | | | | | | | | Provision for depreciation | | | 12 | | | 10 | | Amortization of regulatory assets | | | 29 | | | 25 | | Deferred costs recoverable as regulatory assets | | | (16 | ) | | (17 | ) | Deferred income taxes and investment tax credits, net | | | -- | | | 2 | | Other non-cash expenses | | | (4 | ) | | 1 | | | Cash earnings (Non-GAAP) | | $ | 37 | | $ | 39 | |
The $2$4 million decreaseincrease in cash earnings is described above and under "Results“Results of Operations".Operations.” The $4$5 million working capital change primarily resulted from changesdecreased outflows of $64$51 million in receivablesaccounts payable and $3$1 million in accrued interest, partially offset by changesa $42 million decrease in cash provided from the settlement of $56receivables and a $5 million decrease in accounts payable and $8 million inother accrued taxes.liabilities.
Cash Flows From Financing Activities
Net cash provided from financing activities was $17 million in the first quarter of 2006 compared to $19 million in the first quarter of 2005 compared to $127 million in the first quarter of 2004.2005. The decrease primarily reflected $29reflects an $11 million ofdecrease in short-term borrowings in the first quarter of 2005 compared to last year’s issuance of $250 million of senior notes,2006, partially offset by debt redemptions of $115a $9 million decrease in the first quarter of 2004. In addition, common stock dividendsdividend payments to FirstEnergy increased by $4 million in 2005.FirstEnergy.
As of March 31, 2005,2006, Met-Ed had approximately $22$30 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $109$157 million of short-term borrowings outstanding.borrowings. Met-Ed has authorization from the SEC, continued by FERC rules adopted as a result of EPACT's repeal of PUHCA, to incur short-term debt up to $250 million (includingand authorization from the utilityPPUC to incur money pool).pool borrowings up to $300 million. In addition, Met-Ed has $80 million of available accounts receivable financing facilities as of March 31, 2006 from Met-Ed Funding LLC, Met-Ed’s wholly owned subsidiary. As a separate legal entity with separate creditors, Met-Ed Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Met-Ed. As of March 31, 2006 the facility was drawn for $75 million.
Under the terms of Met-Ed’s senior note indenture, FMB may no more first mortgage bonds canlonger be issued so long as the senior bonds are outstanding. As of March 31, 2006, Met-Ed had the capability to issue $625 million of additional senior notes based upon FMB collateral. Met-Ed had no restrictions on the issuance of preferred stock.
In addition, Met-Ed, has an $80 million customer receivables financing facility. TheFirstEnergy, OE, Penn, CEI, TE, JCP&L, Penelec, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility was undrawnwith a syndicate of banks which expires in June 2010. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment expiration date, as of March 31, 2005; it expires June 30, 2005 andthe same may be extended. Met-Ed’s borrowing limit under the facility is expected to be renewed.$250 million.
Under the revolving credit facility, Borrowers may request the issuance of LOC expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under the existing credit facilities and accounts receivable financing facilities totaled $255 million.
The revolving credit facility contains financial covenants requiring each Borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of March 31, 2006, Met-Ed’s debt to total capitalization as defined under the revolving credit facility was 39%.
The facility does not contain any provisions that either restrict Met-Ed’s ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to Met-Ed's credit ratings.
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 first quarter of 20052006 was 2.66%4.58%.
Met-Ed’s access to the capital markets and the costs of financing are dependent on the ratings of its securities and that of FirstEnergy. As of March 31, 2006, Met-Ed’s and FirstEnergy’s ratings outlook from S&P on all securities was stable. The ratings outlook from Moody’s and Fitch on all securities is stable.
On March 18, 2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affect FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings outlook would be revised to positive.
Cash Flows From Investing Activities
In the first quarter of 2005, net2006, Met-Ed's cash used infor investing activities totaled $22$29 million, compared to $128$22 million in the first quarter of 2004.2005. The decreaseincrease primarily resulted from a $114$9 million increase in property additions, partially offset by a decrease in loans to associated companies offset in part by a $7 million increase in property additions.companies. Expenditures for property additions primarily support Met-Ed’s energy delivery operations.operations and reliability initiatives.
During the remaining three quarters of 2005,2006, capital requirements for property additions are expected to be about $52$56 million. Met-Ed has additional requirements of approximately $37$100 million for maturing long-term debt during the remainder of 2005.2006. These cash requirements are expected to be satisfied from a combination of internal cash, funds raised in the long-term debt capital markets and short-term credit arrangements.
Met-Ed's capital spending for the period 20052006 through 20072010 is expected to be about $205$366 million, of which approximately $82 million applies to 2006. The capital spending is primarily for property additions and energy delivery related improvements,supporting the distribution of which approximately $67 million applies to 2005.electricity.
Market Risk Information
Met-Ed 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 members of senior management, provides general managementoversight to risk management activities throughout the Company.company.
Commodity Price Risk
Met-Ed is exposed to market risk primarily due to fluctuations in electricity, andenergy transmission, natural gas, coal, and emission 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 futures contracts.swaps. The derivatives are used principally for hedging purposes. MostAll derivatives that fall within the scope of Met-Ed's non-hedgeSFAS 133 must be recorded at their fair value and marked to market. The majority of Met-Ed’s derivative hedging contracts represent non-trading positions that do not qualify for hedge treatmentnormal purchase and normal sale exception under SFAS 133. AsContracts that are not exempt from such treatment include purchase power agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policy Act of March 31, 2005, Met-Ed’s commodity derivative contract was an embedded option1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of $27 million. A decreasecommodity derivative contracts related to energy production during the first quarter of $52006 is summarized in the following table:
| | | Three Months Ended | | | | | March 31, 2006 | | Increase (Decrease) in the Fair Value of Derivative Contracts | | Non-Hedge | | Hedge | | Total | | | | | (In millions) | | | Change in the fair value of commodity derivative contracts | | | | | | | | | Outstanding net asset as of January 1, 2006 | | $ | 27 | | $ | - | | $ | 27 | | | New contract value when entered | | | - | | | - | | | - | | | Additions/Changes in value of existing contracts | | | 4 | | | - | | | 4 | | | Change in techniques/assumptions | | | - | | | - | | | - | | | Settled contracts | | | (7 | ) | | - | | | (7 | ) | | | | | | | | | | | | | Net Assets - Derivatives Contracts as of March 31, 2006(1) | | $ | 24 | | $ | - | | $ | 24 | | | | | | | | | | | | | | Impact of Changes in Commodity Derivative Contracts(2) | | | | | | | | | | | | Income Statement Effects (Pre-Tax) | | $ | 2 | | $ | - | | $ | 2 | | | Balance Sheet Effects: | | | | | | | | | | | | OCI (Pre-Tax) | | $ | - | | $ | - | | $ | - | | | Regulatory Liability | | $ | 5 | | $ | - | | $ | 5 | |
(1)Includes $21 million in non-hedge commodity derivative contracts, which are offset by a regulatory liability. (2)Represents the change in value of this asset was recorded as a decreaseexisting contracts, settled contracts and changes in a regulatory liability and, therefore, had no impact on net income.techniques/ assumptions
Derivatives are included on the Consolidated Balance Sheet as of March 31, 2006 as follows:
| | | Non-Hedge | | Hedge | | Total | | | | | (In millions) | | Current- | | | | | | | | | Other assets | | $ | 2 | | $ | - | | $ | 2 | | | Other liabilities | | | - | | | - | | | - | | | | | | | | | | | | | | Non-Current- | | | | | | | | | | | | Other deferred charges | | | 23 | | | - | | | 23 | | | Other noncurrent liabilities | | | (1 | ) | | - | | | (1 | ) | | | | | | | | | | | | | Net assets | | $ | 24 | | $ | - | | $ | 24 | |
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. TheSources of information for the valuation of thecommodity derivative contract atcontracts as of March 31, 2005 is shown using prices from sources2006 are summarized by year in the following table:
Source of Information | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - Fair Value by Contract Year | | 2005 | | 2006 | | 2007 | | 2008 | | 2009 | | Thereafter | | Total | | | 2006(1) | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter | | Total | | | | | (In millions) | | | (In millions) | | Prices based on external sources(1)(2) | | $ | 5 | | $ | 4 | | $ | -- | | $ | -- | | $ | -- | | $ | -- | | $ | 9 | | | $ | (20 | ) | $ | (16 | ) | $ | (17 | ) | $ | - | | $ | - | | $ | - | | $ | (53 | ) | Prices based on models | | | -- | | | -- | | | 6 | | | 5 | | | 3 | | | 4 | | | 18 | | | | - | | | - | | | - | | | (16 | ) | | (12 | ) | | 105 | | | 77 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 5 | | $ | 4 | | $ | 6 | | $ | 5 | | $ | 3 | | $ | 4 | | $ | 27 | | | $ | (20 | ) | $ | (16 | ) | $ | (17 | ) | $ | (16 | ) | $ | (12 | ) | $ | 105 | | $ | 24 | |
(1)For the last three quarters of 2006. (2)Broker quote sheets.sheets (3)Includes $21 million from an embedded option that is offset by a regulatory liability and does not affect earnings.
Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on both of Met-Ed’s trading and non-trading derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of March 31, 2005.2006.
Equity Price Risk
Included in Met-Ed's nuclear decommissioning trust investmentstrusts are marketable equity securities carried at their market value of approximately $131$148 million and $134$142 million as of March 31, 20052006 and December 31, 2004,2005, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $13$15 million reduction in fair value as of March 31, 2005.2006.
OUTLOOKRegulatory Matters
The electric industry continues to transition to a more competitive environment and all of Met-Ed's customers can select alternative energy suppliers. Met-Ed 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. 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. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
Regulatory Matters
Beginning in 1999, all of Met-Ed's customers had a choice for electric generation suppliers. Met-Ed's customer rates were restructured to itemize (unbundle) the current price of electricity into its component elements - including generation, transmission, distribution and stranded cost recovery. In the event customers obtain power from an alternative source, the generation portion of Met-Ed's rates is excluded from their bill and the customers receive a generation charge from the alternative supplier.
Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in the future periods and, withoutor for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income whenas incurred. Met-Ed'sAll regulatory assets are expected to be recovered under the provisions of Met-Ed’s transition plan and rate restructuring plan. Met-Ed’s regulatory assets as of March 31, 20052006 and December 31, 20042005 were $750$308 million and $693$310 million, respectively.
Met-Ed’s and Penelec’s combined portion of total merger savings during 2001 - 2004 is estimated to be approximately $51 million. A procedural schedule was established by the ALJ on January 17, 2006. Met-Ed purchasesand Penelec filed initial testimony on March 1, 2006. Hearings are currently scheduled for the end of October 2006 with the ALJ’s recommended decision to be issued in February 2007. Met-Ed and Penelec have requested that this proceeding be consolidated with the April 10, 2006 transition plan filing proceeding discussed below. Met-Ed is unable to predict the outcome of this proceeding.
In an October 16, 2003 order, the PPUC approved September 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also denied their accounting treatment request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse this PPUC finding; a Commonwealth Court judge subsequently denied their Objection on October 27, 2003 without explanation. On October 31, 2003, Met-Ed and Penelec filed an Application for Clarification of the Court order with the Commonwealth Court, a Petition for Review of the PPUC's October 2 and October 16, 2003 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. The Reargument Brief before the Commonwealth Court was filed on January 28, 2005. Oral arguments are scheduled for June 8, 2006.
On November 18, 2004, the FERC issued an order eliminating the regional through and out rates (RTOR) for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within the MISO and PJM to submit compliance filings containing a mechanism - the Seams Elimination Cost Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be involved in the FERC hearings concerning the calculation and imposition of the SECA charges. The hearing began on May 1, 2006. The FERC has ordered the Presiding Judge to issue an initial decision by August 11, 2006.
On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order. On March 20, 2006 a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued an order approving this settlement on April 19, 2006. If the FERC accepts AEP's proposal, significant additional transmission revenues would be imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within PJM.
As of March 31, 2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation are $328 million and $50 million, respectively. Penelec's $50 million is subject to the pending resolution of taxable income issues associated with NUG trust fund proceeds.
On January 12, 2005, Met-Ed filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. As of March 31, 2006, the PPUC had taken no action on the request and Met-Ed had not yet implemented deferral accounting for these costs. Met-Ed sought to consolidate this proceeding (and modified its request to provide deferral of 2006 transmission-related costs only) with the comprehensive rate filing it made on April 10, 2006 as described below. On May 4, 2006, the PPUC approved the modified request. Accordingly, Met-Ed will implement deferral accounting for these costs in the second quarter of 2006, which will include $24 million representing the amount that was incurred in the first quarter of 2006 -- the deferral of such amount will be reflected in the second quarter of 2006.
Met-Ed and Penelec purchase a portion of itstheir PLR requirements from FES through a wholesale power sales 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 wholesalethis 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 its NUGtheir contracts with NUGs and other power contracts with nonaffiliated third partyunaffiliated suppliers. ThisThe FES arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for itstheir uncommitted PLR energy costs during the term of the agreement with FES. The wholesale power sales agreement with FES could automatically be extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. On November 1, 2005, FES and the other parties thereto amended the agreement to provide FES the right in 2006 to terminate the agreement at any time upon 60 days notice. On April 7, 2006, the parties to the wholesale power sales agreement entered into a Tolling Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the wholesale power sales agreement effective midnight December 31, 2006, because that agreement is authorizednot economically sustainable to continue deferring differences between NUG contract costs and current market prices.FES.
OnIn lieu of allowing such termination to become effective as of December 31, 2006, the parties agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales agreement to provide as follows:
1.The termination provisions of the wholesale power sales agreement will be tolled for one year until December 31, 2007, provided that during such tolling period:
| a. | FES will be permitted to terminate the wholesale power sales agreement at any time with sixty days written notice; |
| b. | Met-Ed and Penelec will procure through arrangements other than the wholesale power sales agreement beginning December 1, 2006 and ending December 31, 2007, approximately 33% of the amounts of capacity and energy necessary to satisfy their PLR obligations for which Committed Resources (i.e., non-utility generation under contract to Met-Ed and Penelec, Met-Ed- and Penelec-owned generating facilities, purchased power contracts and distributed generation) have not been obtained; and |
| c. | FES will not be obligated to supply additional quantities of capacity and energy in the event that a supplier of Committed Resources defaults on its supply agreement. |
2.During the tolling period FES will not act as agent for Met-Ed or Penelec in procuring the services under section 1.(b) above; and
3.The pricing provision of the wholesale power sales agreement shall remain unchanged provided Met-Ed and Penelec comply with the provisions of the Tolling Agreement and any applicable provision of the wholesale power sales agreement.
In the event that FES elects not to terminate the wholesale power sales agreement effective midnight December 31, 2007, similar tolling agreements effective after December 31, 2007 are expected to be considered by FES for subsequent years if Met-Ed and Penelec procure through arrangements other than the wholesale power sales agreement approximately 64%, 83% and 95% of the additional amounts of capacity and energy necessary to satisfy their PLR obligations for 2008, 2009 and 2010, respectively, for which Committed Resources have not been obtained from the market.
The wholesale power sales agreement, as modified by the Tolling Agreement, requires Met-Ed and Penelec to satisfy the portion of their PLR obligations currently supplied by FES from unaffiliated suppliers at prevailing prices, which are likely to be higher than the current price charged by FES under the current agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. There can be no assurance, however, that if FES ultimately determines to terminate, or significantly modify the agreement, timely regulatory relief will be granted by the PPUC pursuant to the April 10, 2006 comprehensive rate filing discussed below, or, to the extent granted, adequate to mitigate such adverse consequences.
Met-Ed and Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 that addresses a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals is approved, the filing would increase annual revenues by $216 million and $157 million, respectively. That filing includes, among other things, a request to charge customers for an increasing amount of market priced power procured through a competitive bid process as the amount of supply provided under the existing FES agreement is phased out in accordance with the April 7, 2006 Tolling agreement described above. Met-Ed and Penelec also requested approval of the January 12, 2005 Met-Ed filed a request withpetition for the PPUC for deferral of transmission-related costs beginningdiscussed above, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2005, estimated2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider similar to that implemented in Ohio. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs are also included in the filing. The filing contemplates a reduction in distribution rates for Met-Ed in the amount of $37 million annually and an increase in distribution rates for Penelec in the amount of $20 million annually. Although the companies have proposed an effective date of June 10, 2006, it is expected that the PPUC will suspend the effective date for seven months as permitted under Pennsylvania law. Hearings are expected to be approximately $4 million per month.scheduled for the second half of 2006 and a PPUC decision is expected early in the first quarter of 2007.
See Note 1311 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania including a more detailed discussion of reliability initiatives, including actions by the PPUC that impactsimpact Met-Ed.
Environmental Matters
Met-Ed accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in Met-Ed'sMet-Ed’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
Met-Ed has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, CompensationResponsive, Comprehension 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 held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2005,2006, based on estimates of the total costs of cleanup, Met-Ed'sMet-Ed’s proportionate responsibility for such costs and the financial ability of other nonaffiliatedunaffiliated entities to pay. Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately $48,000 as
See Note 10(B) to the consolidated financial statements for further details and a complete discussion of March 31, 2005.environmental matters.
Other Legal ProceedingsMatters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Met-Ed'sMet-Ed’s normal business operations pending against Met-Ed. The most significantother material items not otherwise discussed below are described below.in Note 10(C) to the consolidated financial statements.
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. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,concluded, 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 real-time 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 contained 46 "recommendations“recommendations to prevent or minimize the scope of future blackouts."” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in process,new or material upgrades to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother applicable government agencies and reliability coordinators may, however, 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 asFinally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of March 31, 2005 forcontrol room operators before determining the next steps, if any, expenditures in excess of those actually incurred through that date. One complaint was filed on August 25, 2004 against FirstEnergy in the New Yorkproceeding.
FirstEnergy was named in a complaint filed in Michigan State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages asCourt by an individual who is not a result of the August 14, 2003 power outages. None of the plaintiffs are customerscustomer of any FirstEnergy affiliate.company. A responsive pleading to this matter has been filed. FirstEnergy filedwas also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy are based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. No FirstEnergy entity serves any customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss withdismiss. It is uncertain whether the Court on October 22, 2004.plaintiff will appeal. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thusof potential liability has not been determined.undertaken in either of these matters.
FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular,Although unable to predict the impact of these proceedings, 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.operations and cash flows.
New Accounting Standards and Interpretations
FIN 47,“AccountingEITF Issue 04-13, "Accounting for Conditional Asset Retirement Obligations - an interpretationPurchases and Sales of FASB Statement No. 143”Inventory with the Same Counterparty"
On March 30, 2005, the FASB issued this interpretation to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. FirstEnergy is currently evaluating the effect this standard will have on the financial statements.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
In March 2004,September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus on the application guidancethat an exchange of inventory should be accounted 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 valuevalue. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and the impairment loss recognizedother storable inventory. Therefore, Met-Ed will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective forinterim or annual periods beginning after JuneMarch 15, 2004, were delayed by2006. This EITF issue will not have a material impact on Met-Ed's financial results.
SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140” In February 2006, the issuanceFASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of FSP EITF 03-1-1 in September 2004. DuringFinancial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the periodrequirements of delay, FirstEnergy will continueSFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. Met-Ed is currently evaluating the impact of this Statement on its investments as required by existing authoritative guidance.financial statements.
PENNSYLVANIA ELECTRIC COMPANY | PENNSYLVANIA ELECTRIC COMPANY | | PENNSYLVANIA ELECTRIC COMPANY | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | (Unaudited) | (Unaudited) | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | | March 31, | | | | | | | | | | | | | Three Months Ended | | | | | | | 2005 | | 2004 | | | March 31, | | | | | | | | | | | | 2006 | | 2005 | | | | | | | (In thousands) | | | (In thousands) | | | | | | | | | | | | | | | | OPERATING REVENUES | | | | | $ | 293,929 | | $ | 256,445 | | | $ | 291,752 | | $ | 293,929 | | | | | | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | | Purchased power | | | | | 150,277 | | 156,376 | | | | 161,641 | | 150,277 | | | Other operating costs | | | | | 53,793 | | 39,908 | | | | 38,342 | | 53,793 | | | Provision for depreciation | | | | | 12,506 | | 11,438 | | | | 12,643 | | 12,506 | | | Amortization of regulatory assets | | | | | 13,185 | | 13,651 | | | | 14,815 | | 13,185 | | | General taxes | | | | | 18,206 | | 16,962 | | | | 19,389 | | 18,206 | | | Income taxes | | | | | | 15,792 | | | 2,563 | | | | 12,764 | | | 15,792 | | | Total operating expenses and taxes | | | | | | 263,759 | | | 240,898 | | | | 259,594 | | | 263,759 | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | | | 30,170 | | 15,547 | | | | 32,158 | | | 30,170 | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE) (net of income taxes) | | | | | 736 | | (84 | ) | | OTHER INCOME (net of income taxes) | | | | 1,180 | | | 736 | | | | | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | | | | | Interest on long-term debt | | | | | 7,459 | | 7,447 | | | | 6,934 | | 7,459 | | | Allowance for borrowed funds used during construction | | | | | (125 | ) | | (70 | ) | | | (347 | ) | | (125 | ) | | Deferred interest | | | | | -- | | 190 | | | | Other interest expense | | | | | | 2,188 | | | 2,237 | | | | 3,602 | | | 2,188 | | | Net interest charges | | | | | 9,522 | | 9,804 | | | | 10,189 | | | 9,522 | | | | | | | | | | | | | | | | | | NET INCOME | | | | | $ | 21,384 | | $ | 5,659 | | | | 23,149 | | 21,384 | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | OTHER COMPREHENSIVE INCOME: | | | | | | | | | Unrealized gain on derivative hedges | | | | | 16 | | -- | | | | 16 | | 16 | | | Unrealized gain (loss) on available for sale securities | | | | | | (3 | ) | | 8 | | | | Other comprehensive income (loss) | | | | | 13 | | 8 | | | | Income tax related to other comprehensive income | | | | | | (6 | ) | | (3 | ) | | | Other comprehensive income (loss), net of tax | | | | | | 7 | | | 5 | | | | Unrealized loss on available for sale securities | | | | (4 | ) | | (3 | ) | | Other comprehensive income | | | | 12 | | 13 | | | Income tax expense related to other comprehensive income | | | | 6 | | | 6 | | | Other comprehensive income, net of tax | | | | 6 | | | 7 | | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | | | | $ | 21,391 | | $ | 5,664 | | | $ | 23,155 | | $ | 21,391 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company arean integral part of these statements. | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are | | an integral part of these statements. | | an integral part of these statements. | | |
PENNSYLVANIA ELECTRIC COMPANY | | | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | | | March 31, | | December 31, | | | | | | | 2005 | | 2004 | | | | | | | (In thousands) | | ASSETS | | | | | | | | UTILITY PLANT: | | | | | | | | | In service | | | | | $ | 1,962,547 | | $ | 1,981,846 | | | Less - Accumulated provision for depreciation | | | | | | 756,126 | | | 776,904 | | | | | | | | | 1,206,421 | | | 1,204,942 | | | Construction work in progress | | | | | | 25,837 | | | 22,816 | | | | | | | | | 1,232,258 | | | 1,227,758 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | Nuclear plant decommissioning trusts | | | | | | 108,252 | | | 109,620 | | | Non-utility generation trusts | | | | | | 96,738 | | | 95,991 | | | Long-term notes receivable from associated companies | | | | | | 14,164 | | | 14,001 | | | Other | | | | | | 14,589 | | | 18,746 | | | | | | | | | 233,743 | | | 238,358 | | CURRENT ASSETS: | | | | | | | | | | | | Cash and cash equivalents | | | | | | 35 | | | 36 | | | Notes receivable from associated companies | | | | | | 10,271 | | | 7,352 | | | Receivables- | | | | | | | | | | | | Customers (less accumulated provisions of $4,435,000 and $4,712,000, | | | | | | | | | | | | respectively, for uncollectible accounts) | | | | | | 128,530 | | | 121,112 | | | Associated companies | | | | | | 48,645 | | | 97,528 | | | Other | | | | | | 15,098 | | | 12,778 | | | Prepayments and other | | | | | | 42,317 | | | 7,198 | | | | | | | | | 244,896 | | | 246,004 | | DEFERRED CHARGES: | | | | | | | | | | | | Goodwill | | | | | | 887,103 | | | 888,011 | | | Regulatory assets | | | | | | 277,520 | | | 200,173 | | | Other | | | | | | 12,293 | | | 13,448 | | | | | | | | | 1,176,916 | | | 1,101,632 | | | | | | | | $ | 2,887,813 | | $ | 2,813,752 | | CAPITALIZATION AND LIABILITIES | | | | | | | | | | | CAPITALIZATION: | | | | | | | | | | | | Common stockholder's equity- | | | | | | | | | | | | Common stock, $20 par value, authorized 5,400,000 shares - | | | | | | | | | | | | 5,290,596 shares outstanding | | | | | $ | 105,812 | | $ | 105,812 | | | Other paid-in capital | | | | | | 1,205,948 | | | 1,205,948 | | | Accumulated other comprehensive loss | | | | | | (52,806 | ) | | (52,813 | ) | | Retained earnings | | | | | | 62,453 | | | 46,068 | | | Total common stockholder's equity | | | | | | 1,321,407 | | | 1,305,015 | | | Long-term debt and other long-term obligations | | | | | | 478,695 | | | 481,871 | | | | | | | | | 1,800,102 | | | 1,786,886 | | CURRENT LIABILITIES: | | | | | | | | | | | | Currently payable long-term debt | | | | | | 11,525 | | | 8,248 | | | Short-term borrowings- | | | | | | | | | | | | Associated companies | | | | | | 69,693 | | | 241,496 | | | Other | | | | | | 170,000 | | | -- | | | Accounts payable- | | | | | | | | | | | | Associated companies | | | | | | 28,338 | | | 56,154 | | | Other | | | | | | 29,542 | | | 25,960 | | | Accrued taxes | | | | | | 18,204 | | | 7,999 | | | Accrued interest | | | | | | 15,276 | | | 9,695 | | | Other | | | | | | 18,166 | | | 23,750 | | | | | | | | | 360,744 | | | 373,302 | | NONCURRENT LIABILITIES: | | | | | | | | | | | | Power purchase contract loss liability | | | | | | 441,255 | | | 382,548 | | | Asset retirement obligation | | | | | | 67,482 | | | 66,443 | | | Accumulated deferred income taxes | | | | | | 49,680 | | | 37,318 | | | Retirement benefits | | | | | | 119,115 | | | 118,247 | | | Other | | | | | | 49,435 | | | 49,008 | | | | | | | | | 726,967 | | | 653,564 | | COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | | | | | | | | $ | 2,887,813 | | $ | 2,813,752 | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these balance sheets. | | | | | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY | | CONSOLIDATED BALANCE SHEETS | (Unaudited) |
| | | | | | | | | | March 31, | | December 31, | | | | | 2006 | | 2005 | | | | | (In thousands) | | ASSETS | | | | | | UTILITY PLANT: | | | | | | | In service | | $ | 2,070,562 | | $ | 2,043,885 | | | Less - Accumulated provision for depreciation | | | 788,535 | | | 784,494 | | | | | | 1,282,027 | | | 1,259,391 | | | Construction work in progress | | | 33,332 | | | 30,888 | | | | | | 1,315,359 | | | 1,290,279 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 115,534 | | | 113,368 | | | Non-utility generation trusts | | | 97,390 | | | 96,761 | | | Other | | | 11,915 | | | 15,031 | | | | | | 224,839 | | | 225,160 | | CURRENT ASSETS: | | | | | | | | | Cash and cash equivalents | | | 35 | | | 35 | | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $4,304,000 and $4,184,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 123,915 | | | 129,960 | | | Associated companies | | | 10,176 | | | 18,626 | | | Other | | | 10,566 | | | 12,800 | | | Notes receivable from associated companies | | | 18,758 | | | 17,624 | | | Prepayments and other | | | 48,682 | | | 7,936 | | | | | | 212,132 | | | 186,981 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 877,778 | | | 882,344 | | | Prepaid pension costs | | | 90,972 | | | 89,637 | | | Other | | | 26,865 | | | 24,176 | | | | | | 995,615 | | | 996,157 | | | | | $ | 2,747,945 | | $ | 2,698,577 | | CAPITALIZATION AND LIABILITIES | | | | | | | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity- | | | | | | | | | Common stock, $20 par value, authorized 5,400,000 shares- | | | | | | | | | 5,290,596 shares outstanding | | $ | 105,812 | | $ | 105,812 | | | Other paid-in capital | | | 1,197,999 | | | 1,202,551 | | | Accumulated other comprehensive loss | | | (303 | ) | | (309 | ) | | Retained earnings | | | 48,973 | | | 25,823 | | | Total common stockholder's equity | | | 1,352,481 | | | 1,333,877 | | | Long-term debt and other long-term obligations | | | 476,704 | | | 476,504 | | | | | | 1,829,185 | | | 1,810,381 | | CURRENT LIABILITIES: | | | | | | | | | Short-term borrowings- | | | | | | | | | Associated companies | | | 230,474 | | | 261,159 | | | Other | | | 70,000 | | | - | | | Accounts payable- | | | | | | | | | Associated companies | | | 15,915 | | | 33,770 | | | Other | | | 46,509 | | | 38,277 | | | Accrued taxes | | | 23,001 | | | 27,905 | | | Accrued interest | | | 14,306 | | | 8,905 | | | Other | | | 17,329 | | | 19,756 | | | | | | 417,534 | | | 389,772 | | NONCURRENT LIABILITIES: | | | | | | | | | Regulatory liabilities | | | 156,002 | | | 162,937 | | | Asset retirement obligation | | | 73,426 | | | 72,295 | | | Accumulated deferred income taxes | | | 113,419 | | | 106,871 | | | Retirement benefits | | | 104,022 | | | 102,046 | | | Other | | | 54,357 | | | 54,275 | | | | | | 501,226 | | | 498,424 | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | $ | 2,747,945 | | $ | 2,698,577 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these | | balance sheets. | | |
PENNSYLVANIA ELECTRIC COMPANY | PENNSYLVANIA ELECTRIC COMPANY | | PENNSYLVANIA ELECTRIC COMPANY | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | CONSOLIDATED STATEMENTS OF CASH FLOWS | | CONSOLIDATED STATEMENTS OF CASH FLOWS | (Unaudited) | (Unaudited) | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | | March 31, | | | | | | | | | | | | | | | | | Three Months Ended | | | | | | | 2005 | | 2004 | | | March 31, | | | | | | | | | | | | 2006 | | 2005 | | | | | | | (In thousands) | | | (In thousands) | | | | | | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | | | | Net income | | | | | $ | 21,384 | | $ | 5,659 | | | $ | 23,149 | | $ | 21,384 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | | | | | | | Provision for depreciation | | | | | 12,506 | | 11,438 | | | | 12,643 | | 12,506 | | | Amortization of regulatory assets | | | | | 13,185 | | 13,651 | | | | 14,815 | | 13,185 | | | Deferred costs recoverable as regulatory assets | | | | | (19,433 | ) | | (17,993 | ) | | | (19,211 | ) | | (19,433 | ) | | Deferred income taxes and investment tax credits, net | | | | | 2,446 | | 25,242 | | | | 5,361 | | 2,446 | | | Accrued retirement benefit obligation | | | | | 868 | | 2,802 | | | | Accrued compensation, net | | | | | (2,630 | ) | | 2,255 | | | | Accrued compensation and retirement benefits | | | | (472 | ) | | (1,762 | ) | | Commodity derivative transactions, net | | | | (4,206 | ) | | - | | | Decrease (Increase) in operating assets: | | | | | | | | | | | | | | | | Receivables | | | | | 39,145 | | (12,129 | ) | | | 16,729 | | 39,145 | | | Prepayments and other current assets | | | | | (35,119 | ) | | (47,054 | ) | | | (36,540 | ) | | (35,119 | ) | | Increase (Decrease) in operating liabilities: | | | | | | | | | | | | | | | | Accounts payable | | | | | (24,234 | ) | | (10,738 | ) | | | (9,623 | ) | | (24,234 | ) | | Accrued taxes | | | | | 10,205 | | (6,483 | ) | | | (4,904 | ) | | 10,205 | | | Accrued interest | | | | | 5,581 | | 2,636 | | | | 5,401 | | 5,581 | | | Other | | | | | | (217 | ) | | 3,654 | | | | (6,745 | ) | | (217 | ) | | Net cash provided from (used for) operating activities | | | | | | 23,687 | | | (27,060 | ) | | | (3,603 | ) | | 23,687 | | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | New Financing- | | | | | | | | | | | | | | | | Long-term debt | | | | | -- | | 150,000 | | | | Short-term borrowings, net | | | | 39,315 | | - | | | Redemptions and Repayments- | | | | | | | | | | | | | | | | Long-term debt | | | | | (13 | ) | | (104 | ) | | | - | | (13 | ) | | Short-term borrowings, net | | | | | (1,803 | ) | | (61,326 | ) | | | - | | (1,803 | ) | | Dividend Payments- | | | | | | | | | | | | | | | | Common stock | | | | | | (5,000 | ) | | -- | | | | - | | | (5,000 | ) | | Net cash provided from (used for) financing activities | | | | | | (6,816 | ) | | 88,570 | | | | 39,315 | | | (6,816 | ) | | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | Property additions | | | | | (15,393 | ) | | (11,194 | ) | | | (35,610 | ) | | (15,393 | ) | | Non-utility generation trust contribution | | | | | -- | | (50,614 | ) | | | Loans to associated companies, net | | | | | (3,082 | ) | | (71 | ) | | | (1,134 | ) | | (3,082 | ) | | Proceeds from nuclear decommissioning trust fund sales | | | | 14,942 | | 7,778 | | | Investments in nuclear decommissioning trust funds | | | | (14,942 | ) | | (7,778 | ) | | Other, net | | | | | | 1,603 | | | 369 | | | | 1,032 | | | 1,603 | | | Net cash used for investing activities | | | | | | (16,872 | ) | | (61,510 | ) | | | (35,712 | ) | | (16,872 | ) | | | | | | | | | | | | | | | | | | Net change in cash and cash equivalents | | | | | (1 | ) | | -- | | | | - | | (1 | ) | | Cash and cash equivalents at beginning of period | | | | | | 36 | | | 36 | | | | 35 | | | 36 | | | Cash and cash equivalents at end of period | | | | | $ | 35 | | $ | 36 | | | $ | 35 | | $ | 35 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are anintegral part of these statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an | | integral part of these statements. | | integral part of these statements. |
Report of Independent Registered Public Accounting Firm
To the StockholdersStockholder and Board of Directors of Pennsylvania Electric Company:
We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of March 31, 2005,2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 20052006 and 2004.2005. 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 as of December 31, 2004,2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004;(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 and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 2(G) 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 69 to those consolidated financial statements) dated March 7, 2005,February 27, 2006, we expressed an unqualified opinions thereon. Theopinion on those consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein.statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004,2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP Cleveland, Ohio May 3, 20058, 2006
PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern, western and south central 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.
Results of Operations
Net income in the first quarter of 20052006 increased to $21$23 million, compared to $6$21 million in the first quarter of 2004.2005. The increase resulted from higherlower other operating revenues and lower purchased power costs, partially offset by lower operating revenues and higher other operating costs and general taxes.purchased power costs.
Operating revenues increaseddecreased by $37$2 million in the first quarter of 20052006 compared to the first quarter of 2004,2005, primarily due to lower transmission and distribution revenues partially offset by higher transmission, retail generation and distribution revenues. Transmission revenues increased $23decreased by $12 million as a result of Penelec's assumption of transmission revenues from FES due to lower transmission load requirements and lower prices. The decreased loads (and related lower congestion revenues) reflect milder temperatures in 2006 compared with 2005, as demonstrated by a change14.6% decrease in the power supply agreement with FES in the second quarter of 2004,heating degree days, and which also resulted in higherlower transmission expenses discussed further below. Distribution revenues decreased by $2 million due to a 2.6% decrease in KWH deliveries reflecting the effect of the unseasonably mild weather, partially offset by slightly higher composite unit prices.
Retail generation revenues increased by $11 million primarily due to a 15.1% increase in industrial KWH sales and higher composite unit prices that resulted in increased revenues in all customer sectors (residential - $2 million; commercial - $2 million; and industrial - $7 million). The industrial sales volume increased primarily from reduced generation service provided by alternative suppliers, which decreased by 14.3 percentage points in the first quarter of 2006. In addition, other operating revenues increased by $1 million due to a higher payment received in the higher first quarter 2005 operating revenues included a $2 million payment receivedof 2006 under a contract provision associated with the prior sale of TMI Unit 1. Under the contract, additional payments are received if subsequent energy prices rise above specified levels.levels, which occurred. This payment is credited to Penelec’s customers, resulting in no net earnings effect.
Retail generation revenues increased by $9 million, principally from increased generation sales to industrial and commercial customers (industrial - $5 million and commercial - $4 million) reflecting volume sales increases of 12.5% and 6.8%, respectively, and higher unit costs. Industrial Changes in KWH sales increased despite higherby customer shopping in this sector. Sales by alternative suppliers as a percent of total industrial sales delivered in Penelec’s franchise area increased by 4.0 percentage points, while commercial customer shopping remained constantclass in the first quarter of 2005. Residential generation revenues showed a slight increase of $0.4 million and residential KWH sales were nearly unchanged in the first quarter of 2005 as compared to last year.
Distribution revenues increased by $3 million in the first quarter of 2005 as2006 compared to the same period of 2004, primarily on higher deliveries to the commercial and industrial sectors. The higher commercial and industrial revenues of $2 million and $1 million, respectively, reflected the effect of increased KWH deliveries partially offset by lower composite unit prices.
Changes in electric distribution deliveries in the first quarter 2005 compared to the first quarter 2004 are summarized in the following table:
| | | | Changes in KWH DeliveriesSales | | 2005
| | Increase (Decrease) | | | | | Retail Electric Generation: | | | | | Residential | | | 0.5(2.2 | )% | | Commercial | | | 6.9(1.4 | )% | | Industrial | | | 18.415.1 | % | Total KWHRetail Electric Generation Sales | | | 2.8 | % | | | | | | | Distribution Deliveries: | | | | | | Residential | | | (2.4 | )% | | Commercial | | | (2.5 | )% | | Industrial | | | (3.1 | )% | Total Distribution Deliveries | | | 8.0
(2.6 | )% | | | | | |
Operating Expenses and Taxes
Total operating expenses and taxes increased by $23 million or 9.5% in the first quarter 2005 from the first quarter of 2004. Purchased power costs decreased by $6$4 million or 3.9% in the first quarter of 2005,2006 compared to the first quarter 2004.of 2005. The decrease was duefollowing table presents changes from the prior year by expense category:
| | | | | Operating Expenses and Taxes - Changes (In millions) | | | | | | | | | Increase (Decrease) | | | | | Purchased power costs | | $ | 11 | | | Other operating costs | | | (15 | ) | | Provision for depreciation | | | - | | | Amortization of regulatory assets | | | 2 | | | General taxes | | | 1 | | | Income taxes | | | (3 | ) | Total operating expenses and taxes | | $ | (4 | ) | | | | | | |
Purchased power costs increased by $11 million or 7.6% in the first quarter of 2006, compared to the first quarter of 2005. The increase is primarily attributable to lowerhigher unit costs slightly offset byfrom non-affiliated suppliers and increased KWH purchased to meet increased retail generation sales requirements. Other operating costs increased by $14 million or 34.8%decreased due to lower transmission expenses resulting from lower congestion charges and to higher levels of construction activities in the first quarter 2005,of 2006 compared to first quarter 2004. That increase was primarily duetoa higher level of maintenance activities in the same period of 2005 for energy delivery operations and reliability initiatives. Amortization of regulatory assets increased transmission expenses in 2005, which were assumed by Penelec due to a changeincreases in the power supply agreement with FES discussed above. In addition, there were higher storm-related contractor costs inCTC revenue recovery compared to the first quarter of 2005.
General taxes increased $1 million due to the higher Pennsylvania gross receipts taxes in the first quarter of 20052006 compared to the same period in 2004.2005. Income taxes increaseddecreased $3 million due to higherlower pre-tax income in the first quarter of 20052006 compared to the first quarter of 2004.2005.
Capital Resources and Liquidity
Penelec’s cash requirements in 2005 and thereafter,2006 for operating expenses, construction expenditures and scheduled debt maturities, are expected to be met by a combination of cash from operations and funds from the capital markets.short-term credit arrangements.
Changes in Cash Position
As of March 31, 2006 and December 31, 2005, Penelec had $35,000 of cash and cash equivalents compared with $36,000 as of December 31, 2004. The major sources for changes in these balances are summarized below.equivalents.
Cash Flows From Operating Activities
Net cash used for operating activities was $4 million in the first quarter of 2006, compared to net cash provided from operating activities wasof $24 million in the first quarter of 2005, compared to net cash used for operating activities of $27 million in 2004, summarized as follows:
| | | | Three Months Ended | | | | | | March 31, | | Operating Cash Flows | | 2005 | | 2004 | | | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | (In millions) | | Cash earnings(1) | | $ | 28 | | $ | 43 | | | $ | 32 | | $ | 28 | | | Working capital and other | | | (4 | ) | | (70 | ) | | | | (36 | ) | | (4 | ) | Total | | $ | 24 | | $ | (27 | ) | | Net cash provided from (used for) Operating Activities | | | | $ | (4 | ) | $ | 24 | |
(1)Cash earnings is a non-GAAP measure (see reconciliation below).
Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. Penelec believes that cash earnings isare a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance.
| | | | Three Months Ended | | | | | | March 31, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | (In millions) | | | Net Income (GAAP) | | $ | 21 | | $ | 6 | | | $ | 23 | | $ | 21 | | | Non-Cash Charges (Credits): | | | | | | | | | | | | | | Provision for depreciation | | | 13 | | | 11 | | | | 13 | | 13 | | Amortization of regulatory assets | | | 13 | | | 14 | | | | 15 | | 13 | | Deferred costs recoverable as regulatory assets | | | (19 | ) | | (18 | ) | | | (19 | ) | | (19 | ) | Deferred income taxes and investment tax credits | | | 2 | | | 25 | | | | 5 | | 2 | | | Commodity derivative transactions, net | | | | (4 | ) | | - | | Other non-cash expenses | | | (2 | ) | | 5 | | | | (1 | ) | | (2 | ) | Cash earnings (Non-GAAP) | | $ | 28 | | $ | 43 | | | $ | 32 | | $ | 28 | |
The $15$4 million decreaseincrease in cash earnings is described above under “Results of Operations.” The $32 million decrease in working capital primarily resulted from a decrease of $22 million in cash provided from the settlement of receivables and under "Resultsdecreases of Operations". This was$15 million in accrued taxes and $2 million in accrued liabilities for consumer education, partially offset by a $66decrease of $14 million change in working capital principally due to changes in receivables, prepayments and accrued taxes, partially offset by a change in the accounts payable.
Cash Flows From Financing Activities
Net cash provided from financing activities was $39 million in the first quarter of 2006 compared to net cash used for financing activities wasof $7 million in the first quarter of 2005 compared to net cash provided from financing activities of $89 million in the first quarter of 2004.2005. The net change reflects the absence of 2004 long-term debt financing of $150a $41 million a $60 million decreaseincrease in debt redemptionsshort-term borrowings and a $5 million ofreduction in common stock dividend payments to FirstEnergy in the first quarter of 2005.2006.
Penelec had approximately $10$19 million of cash and temporary investments (which includeincludes short-term notes receivable from associated companies) and approximately $240$300 million of short-term indebtedness as of March 31, 2005.2006. Penelec has authorization from the SEC, continued by FERC rules adopted as a result of EPACT's repeal of PUHCA, to incur short-term debt of up to $250 million (includingand authorization from the utilityPPUC to incur money pool).pool borrowings of up to $300 million. In addition, Penelec has $75 million of available accounts receivable financing facilities as of March 31, 2006 from Penelec Funding, Penelec's wholly owned subsidiary. As a separate legal entity with separate creditors, Penelec Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penelec. As of March 31, 2006 the facility was drawn for $70 million.
Penelec will not issue FMB other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) Penelec from issuing any debt which is senior to the senior notes. As of March 31, 2005,2006, Penelec did not havehad the ability to issue $39 million of additional senior notes based upon FMB collateral. Penelec has no restrictions on the issuance of preferred stock.
In addition, Penelec, hasFirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, FES and ATSI, as Borrowers, have entered into a $75 million customer receivables financingsyndicated $2 billion five-year revolving credit facility that was drawn for $70 millionwhich expires in June 2010. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as of March 31, 2005. Thethe same may be extended. Penelec's borrowing limit under the facility expires on June 30, 2005, and is expected to be renewed.$250 million.
Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under existing credit facilities and accounts receivable financing facilities totaled $255 million.
The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of March 31, 2006, Penelec’s debt to total capitalization as defined under the revolving credit facility was 36%.
The facility does not contain any provisions that either restrict Penelec's ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to Penelec's credit ratings.
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. Companies receiving a loan under the money pool agreements must repay the principal, 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 under these arrangements in the first quarter of 20052006 was 2.66%4.58%.
Penelec’s access to capital markets and costs of financing are dependent on the ratings of its securities and that of FirstEnergy. The ratings outlook from S&P on all securities is stable.
On March 18, 2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affect FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the The ratings outlook would be revised tofrom Moody's and Fitch on all securities is positive.
Cash Flows From Investing Activities Cash used for investing activities was $17 million in the first quarter of 2005 compared to $62 million in the first quarter of 2004. The decrease was primarily due to the absence in 2005 of a $51 million repayment to the NUG trust fund in 2004, partially offset by increased loans of $3 million to associated companies. In both periods, cash outflows for property additions were made to support the distribution of electricity.
During the remaining three quarters of 2005,2006, capital requirements for property additions are expected to be about $73$66 million. Penelec has additional requirements of approximately $11 million for maturing long-term debt during the remainder of 2005. Those requirements are expected to be satisfied from internal cash and short-term credit arrangements.
Penelec’s capital spending for the period 2005-20072006-2010 is expected to be about $272$489 million, of which approximately $103 million applies to 2006. The capital spending is primarily for property additions and improvements,supporting the distribution of which about $89 million applies to 2005.electricity.
Market Risk Information
Penelec 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 members of senior management, provides general management oversight to risk management activities throughout the Company.
Commodity Price Risk
Penelec is exposed to market risk primarily due to fluctuations in electricity, andenergy transmission, natural gas, coal, and emission prices. To manage the volatility relating to these exposures, itPenelec uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and futures contracts.swaps. The derivatives are used principally for hedging purposes. All derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of Penelec’s non-hedge derivative hedging contracts represent non-trading positions that do not qualify for hedge treatmentthe normal purchase and normal sale exception under SFAS 133. AsContracts that are not exempt from such treatment include purchase power agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policy Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the first quarter 2006 is summarized in the following table:
| | | Three Months Ended | | | | | March 31, 2006 | | Increase (Decrease) in the Fair Value of Derivative Contracts | | Non-Hedge | | Hedge | | Total | | | | | (In millions) | | | Change in the fair value of commodity derivative contracts | | | | | | | | | Outstanding net asset at beginning of period | | $ | 27 | | $ | - | | $ | 27 | | | New contract value when entered | | | - | | | - | | | - | | | Additions/Changes in value of existing contracts | | | 3 | | | - | | | 3 | | | Change in techniques/assumptions | | | - | | | - | | | - | | | Settled contracts | | | - | | | - | | | - | | | | | | | | | | | | | | Net Assets - Derivatives Contracts as of March 31, 2006(1) | | $ | 30 | | $ | - | | $ | 30 | | | | | | | | | | | | | | Impact of Changes in Commodity Derivative Contracts(2) | | | | | | | | | | | | Income Statement Effects (Pre-Tax) | | $ | 6 | | $ | - | | $ | 6 | | | Balance Sheet Effects: | | | | | | | | | | | | OCI (Pre-Tax) | | $ | - | | $ | - | | $ | - | | | Regulatory Asset (net) | | $ | 3 | | $ | - | | $ | 3 | |
| (1) | Includes $11 million in non-hedge commodity derivative contracts, which are offset by a regulatory liability. |
| (2) | Represents the decrease in value of existing contracts, settled contracts and changes in techniques/ assumptions. |
Derivatives are included on the Consolidated Balance Sheet as of March 31, 2005, Penelec’s commodity derivatives contract was an embedded option with a fair value of $14 million. A decrease of $1 million in the value of this asset was recorded2006 as a decrease in a regulatory liability and, therefore, had no impact on net income.follows:
| | | Non-Hedge | | Hedge | | Total | | | | | (In millions) | | Current- | | | | | | | | Other assets | | $ | 4 | | $ | - | | $ | 4 | | Other liabilities | | | - | | | - | | | - | | | | | | | | | | | | | | Non-Current- | | | | | | | | | | | Other deferred charges | | | 26 | | | - | | | 26 | | Other noncurrent liabilities | | | - | | | - | | | - | | | | | | | | | | | | | | Net assets | | $ | 30 | | $ | - | | $ | 30 | |
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, 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. TheSources of information for the valuation of thecommodity derivative contract atcontracts as of March 31, 2005 uses prices from sources shown2006 are summarized by year in the following table:
Source of Information | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | —Fair Value by Contract Year | | 2005 | | 2006 | | 2007 | | 2008 | | 2009 | | Thereafter | | Total | | | Fair Value by Contract Year | | | 2006(1) | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter | | Total | | | | | (In millions) | | | (In millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Prices based on external sources(1) | | $ | 3 | | $ | 3 | | $ | -- | | $ | -- | | $ | -- | | $ | -- | | $ | 6 | | | Other external sources (2) | | | $ | (14 | ) | $ | (3 | ) | $ | 2 | | $ | - | | $ | - | | $ | - | | $ | (15 | ) | | Prices based on models | | | -- | | | -- | | | 2 | | | 2 | | | 2 | | | 2 | | | 8 | | | | - | | | - | | | - | | | 5 | | | 3 | | | 37 | | | 45 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 3 | | $ | 3 | | $ | 2 | | $ | 2 | | $ | 2 | | $ | 2 | | $ | 14 | | | $ | (14 | ) | $ | (3 | ) | $ | 2 | | $ | 5 | | $ | 3 | | $ | 37 | | $ | 30 | |
(1) For the last three quarters of 2006. (2)Broker quote sheets. (3) Includes $11 million from an embedded option that is offset by a regulatory liability and does not affect earnings.
Penelec performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on both itsof Penelec's trading and nontradingnon-trading derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of March 31, 2005.2006. Penelec estimates that if energy commodity prices experienced an adverse 10% change, net income for the next 12 months would not change, as the prices for all commodity positions are already above the contract price caps.
Equity Price Risk Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $58$65 million and $60$62 million as of March 31, 20052006 and December 31, 2004,2005, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6$7 million reduction in fair value as of March 31, 2005.2006.
OutlookRegulatory Matters
The electric industry continues to transition to a more competitive environmentRegulatory assets and all of Penelec's customers can select alternative energy suppliers. Penelec 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. 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. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
Regulatory Matters
Beginning in 1999, all of Penelec's customers had a choice for electric generation suppliers. Penelec's customer rates were restructured to itemize (unbundle) the current price of electricity into its component elements - including generation, transmission, distribution and stranded cost recovery. In the event customers obtain power from an alternative source, the generation portion of Penelec's rates is excluded from their bill and the customers receive a generation charge from the alternative supplier.
Regulatory assetsliabilities are costs which have been authorized by the PPUC and the FERC for recovery from or credit to customers in future periods and, without such authorization, would have been charged or credited to income when incurred. Penelec'sPenelec’s net regulatory assetsliabilities were approximately $156 million and $163 million as of March 31, 20052006 and December 31, 2004 were $278 million2005, respectively, and $200 million, respectively.are included under Noncurrent Liabilities on the Consolidated Balance Sheets.
Met-Ed’s and Penelec’s combined portion of total merger savings during 2001 - 2004 is estimated to be approximately $51 million. A procedural schedule was established by the ALJ on January 17, 2006. Met-Ed and Penelec purchasesfiled initial testimony on March 1, 2006. Hearings are currently scheduled for the end of October 2006 with the ALJ’s recommended decision to be issued in February 2007. Met-Ed and Penelec have requested that this proceeding be consolidated with the April 10, 2006 transition plan filing proceeding as discussed below. Penelec is unable to predict the outcome of this proceeding.
In an October 16, 2003 order, the PPUC approved September 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also denied their accounting treatment request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse this PPUC finding; a Commonwealth Court judge subsequently denied their Objection on October 27, 2003 without explanation. On October 31, 2003, Met-Ed and Penelec filed an Application for Clarification of the Court order with the Commonwealth Court, a Petition for Review of the PPUC's October 2 and October 16, 2003 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. The Reargument Brief before the Commonwealth Court was filed on January 28, 2005. Oral arguments are scheduled for June 8, 2006.
On November 18, 2004, the FERC issued an order eliminating the regional through and out rates (RTOR) for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within the MISO and PJM to submit compliance filings containing a mechanism - the Seams Elimination Cost Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be involved in the FERC hearings concerning the calculation and imposition of the SECA charges. The hearing began on May 1, 2006. The FERC has ordered the Presiding Judge to issue an initial decision by August 11, 2006. On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order. On March 20, 2006 a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued an order approving this settlement on April 19, 2006. If the FERC accepts AEP's proposal, significant additional transmission revenues would be imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within PJM.
As of March 31, 2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation are $328 million and $50 million, respectively. Penelec's $50 million is subject to the pending resolution of taxable income issues associated with NUG trust fund proceeds.
On January 12, 2005, Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. As of March 31, 2006, the PPUC had taken no action on the request and Penelec had not yet implemented deferral accounting for these costs. Penelec sought to consolidate this proceeding (and modified its request to provide deferral of 2006 transmission-related costs only) with the comprehensive rate filing it made on April 10, 2006 as described below. On May 4, 2006, the PPUC approved the modified request. Accordingly, Penelec will implement deferral accounting for these costs in the second quarter of 2006, which will include $4 million representing the amount that was incurred in the first quarter of 2006 -- the deferral of such amount will be reflected in the second quarter of 2006.
Met-Ed and Penelec purchase a portion of itstheir PLR requirements from FES through a wholesale power sales 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 wholesalethis 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 its NUGtheir contracts with NUGs and other power contracts with nonaffiliated third partyunaffiliated suppliers. ThisThe FES arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for itstheir uncommitted PLR energy costs during the term of the agreement with FES. The wholesale power sales agreement with FES could automatically be extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. On November 1, 2005, FES and the other parties thereto amended the agreement to provide FES the right in 2006 to terminate the agreement at any time upon 60 days notice. On April 7, 2006, the parties to the wholesale power sales agreement entered into a Tolling Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the wholesale power sales agreement effective midnight December 31, 2006, because that agreement is authorizednot economically sustainable to continue deferring differences between NUG contract costs and current market prices.FES.
In lieu of allowing such termination to become effective as of December 31, 2006, the parties agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales agreement to provide as follows:
On1.The termination provisions of the wholesale power sales agreement will be tolled for one year until December 31, 2007, provided that during such tolling period:
| a. | FES will be permitted to terminate the wholesale power sales agreement at any time with sixty days written notice; |
| b. | Met-Ed and Penelec will procure through arrangements other than the wholesale power sales agreement beginning December 1, 2006 and ending December 31, 2007, approximately 33% of the amounts of capacity and energy necessary to satisfy their PLR obligations for which Committed Resources (i.e., non-utility generation under contract to Met-Ed and Penelec, Met-Ed- and Penelec-owned generating facilities, purchased power contracts and distributed generation) have not been obtained; and |
| c. | FES will not be obligated to supply additional quantities of capacity and energy in the event that a supplier of Committed Resources defaults on its supply agreement. |
2.During the tolling period FES will not act as agent for Met-Ed or Penelec in procuring the services under section 1.(b) above; and
3.The pricing provision of the wholesale power sales agreement shall remain unchanged provided Met-Ed and Penelec comply with the provisions of the Tolling Agreement and any applicable provision of the wholesale power sales agreement.
In the event that FES elects not to terminate the wholesale power sales agreement effective midnight December 31, 2007, similar tolling agreements effective after December 31, 2007 are expected to be considered by FES for subsequent years if Met-Ed and Penelec procure through arrangements other than the wholesale power sales agreement approximately 64%, 83% and 95% of the additional amounts of capacity and energy necessary to satisfy their PLR obligations for 2008, 2009 and 2010, respectively, for which Committed Resources have not been obtained from the market.
The wholesale power sales agreement, as modified by the Tolling Agreement, requires Met-Ed and Penelec to satisfy the portion of their PLR obligations currently supplied by FES from unaffiliated suppliers at prevailing prices, which are likely to be higher than the current price charged by FES under the current agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. There can be no assurance, however, that if FES ultimately determines to terminate, or significantly modify the agreement, timely regulatory relief will be granted by the PPUC pursuant to the April 10, 2006 comprehensive rate filing discussed below, or, to the extent granted, adequate to mitigate such adverse consequences.
Met-Ed and Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 that addresses a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals is approved, the filing would increase annual revenues by $216 million and $157 million, respectively. That filing includes, among other things, a request to charge customers for an increasing amount of market priced power procured through a competitive bid process as the amount of supply provided under the existing FES agreement is phased out in accordance with the April 7, 2006 Tolling agreement described above. Met-Ed and Penelec also requested approval of the January 12, 2005 Penelec filed a request withpetition for the PPUC for deferral of transmission-related costs beginningdiscussed above, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2005, estimated2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider similar to that implemented in Ohio. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs are also included in the filing. The filing contemplates a reduction in distribution rates for Met-Ed in the amount of $37 million annually and an increase in distribution rates for Penelec in the amount of $20 million annually. Although the companies have proposed an effective date of June 10, 2006, it is expected that the PPUC will suspend the effective date for seven months as permitted under Pennsylvania law. Hearings are expected to be approximately $4 million per month.scheduled for the second half of 2006 and a PPUC decision is expected early in the first quarter of 2007.
See Note 1311 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania, including a more detailed discussion of reliability initiatives, including actions by the PPUC that impact Penelec.
Environmental Matters
Penelec accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs 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.
Penelec has been named 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.
Other Legal Proceedings
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Penelec'sPenelec’s normal business operations pending against Penelec. The most significantother material items not otherwise discussed below are described below.in Note 10(C) to the consolidated financial statements.
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. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,concluded, 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 real-time 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 contained 46 "recommendations“recommendations to prevent or minimize the scope of future blackouts."” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in process,new or material upgrades to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother applicable government agencies and reliability coordinators may, however, 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 asFinally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of March 31, 2005 forcontrol room operators before determining the next steps, if any, expenditures in excess of those actually incurred through that date.the proceeding.
One FirstEnergy was named in a complaint was filed on August 25, 2004 against FirstEnergy in the New YorkMichigan State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages asCourt by an individual who is not a result of the August 14, 2003 power outages. None of the plaintiffs are customerscustomer of any FirstEnergy affiliate.company. A responsive pleading to this matter has been filed. FirstEnergy filedwas also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy are based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. No FirstEnergy entity serves any customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss withdismiss. It is uncertain whether the Court on October 22, 2004.plaintiff will appeal. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thusof potential liability has not been determined.undertaken in either of these matters.
FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against 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.
New Accounting Standards and Interpretations
FIN 47,“AccountingEITF Issue 04-13, "Accounting for Conditional Asset Retirement Obligations - an interpretationPurchases and Sales of FASB Statement No. 143”Inventory with the Same Counterparty"
On March 30, 2005, the FASB issued this interpretation to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. FirstEnergy is currently evaluating the effect this standard will have on the financial statements.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
In March 2004,September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus on the application guidancethat an exchange of inventory should be accounted 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 valuevalue. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and the impairment loss recognizedother storable inventory. Therefore, Penelec will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective forinterim or annual periods beginning after JuneMarch 15, 2004, were delayed by2006. This EITF issue will not have a material impact on Penelec's financial results.
SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140” In February 2006, the issuanceFASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of FSP EITF 03-1-1 in September 2004. DuringFinancial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the periodrequirements of delay, FirstEnergy will continueSFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. Penelec is currently evaluating the impact of this Statement on its investments as required by existing authoritative guidance.financial statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See“Management’s “Management’s Discussion and Analysis of Results of Operation and Financial Condition - Market Risk Information”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. The term disclosure controls and procedures as definedmeans controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 Rules 13a-15(e)(15 U.S.C. 78a et seq.) is recorded, processed, summarized and 15d-15(e),reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as of the end of the date covered by this report.appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that the applicable registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to the registrant and its consolidated subsidiaries by others within those entities.
(b) CHANGES IN INTERNAL CONTROLS During the quarter ended March 31, 2005,2006, 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.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 1210 and 1311 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. ITEM 1A.RISK FACTORS
Not Applicable.
ITEM 2. CHANGES INUNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES
(e)(c) FirstEnergy
The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock. | | | | | | | | | Maximum Number | | | | | | | | | | | (or Approximate | | | | | | | | | Total Number of | | Dollar Value) of | | | | | | | | | Shares Purchased | | Shares that May | | | | | Total Number | | | | As Part of Publicly | | Yet Be Purchased | | | | | of Shares | | Average Price | | Announced Plans | | Under the Plans | | Period | | Purchased (a) | | Paid per Share | | or Programs (b) | | or Programs | | | | | | | | | | | | | | January 1-31, 2005 | | | 62,712 | | $ | 39.23 | | | -- | | | -- | | | February 1-28, 2005 | | | 104,824 | | $ | 40.78 | | | -- | | | -- | | | March 1-31, 2005 | | | 942,459 | | $ | 41.59 | | | -- | | | -- | | | | | | | | | | | | | | | | | | First Quarter 2005 | | | 1,109,995 | | $ | 41.38 | | | -- | | | -- | |
| | | Period | | | | | January 1-31, | | February 1-28, | | March 1-31, | | First | | | | | 2006 | | 2006 | | 2006 | | Quarter | | Total Number of Shares Purchased (a) | | 150,321 | | 143,522 | | 769,145 | | 1,062,988 | | | Average Price Paid per Share | | $50.77 | | $50.67 | | $50.84 | | $50.81 | | | Total Number of Shares Purchased | | | | | | | | | | As Part of Publicly Announced Plans | | | | | | | | | | or Programs (b) | | | - | | | - | | | - | | | - | | | Maximum Number (or Approximate Dollar | | | | | | | | | | | | | | Value) of Shares that May Yet Be | | | | | | | | | | | | | | Purchased Under the Plans or Programs | | | - | | | - | | | - | | | - | | | | | | | | | | | | | | | | |
(a)Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its Executive and Director Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the Executive and Director Incentive Compensation Plan.
(a) | Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its Executive and Director Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the Executive and Director Incentive Compensation Plan. | | | | (b) | FirstEnergy does not currently have any publicly announced plan or program for share purchases. |
ITEM 6. EXHIBITS
(a)Exhibits
Exhibit Number | | Number
| | | | | | Met-EdFirstEnergy
| | | | | | | | 1210.1* | Fixed charge ratios | | 31.1 | CertificationForm of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | Penelec
| | | | | | 10.1 | Term LoanGuaranty Agreement dated as of March 15, 2005,April 3, 2006 by FirstEnergy Corp. in favor of the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent, under the related Letter of Credit and Reimbursement Agreement.
| | 10.2* | Form of Letter of Credit and Reimbursement Agreement dated as of April 3, 2006 among FirstEnergy Generation Corp., the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent. | | 10.3* | Form of Trust Indenture dated as of April 1, 2006 between the Ohio Water Development Authority and The Bank of New York Trust Company, N.A. as Trustee securing pollution control revenue refunding bonds issued on behalf of FirstEnergy Generation Corp. | | 10.4* | Form of Waste Water Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Generation Corp. dated as of April 1, 2006. |
| 10.5 | Notice of Termination Tolling Agreement dated as of April 7, 2006; Restated Partial Requirements Agreement, dated January 1, 2003, by and among, Metropolitan Edison Company, Pennsylvania Electric Company, Union Bank of California, N.A.The Waverly Electric Power and Light Company and FirstEnergy Solutions Corp., as Administrative Agent, Lead Arrangeramended by a First Amendment to Restated Requirements Agreement, dated August 29, 2003 and Lender,by a Second Amendment to Restated Requirements Agreement, dated June 8, 2004 (“Partial Requirements Agreement”). (Form 8-K dated April 10, 2006)
| | 10.6 | Form of Restricted Stock Agreement between FirstEnergy and National City Bank as Arranger, Syndication AgentA. J. Alexander, dated February 27, 2006. | | 10.7 | Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy and Lender. (March 18, 2005 A.J. Alexander, dated March 1, 2006.
| | 10.8 | Form 8-K, Exhibit 10.1).of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy and named executive officers, dated March 1, 2006. | | 10.9 | Form of Restricted Stock Unit Agreement (Discretionary) between FirstEnergy and R.H. Marsh, dated March 1, 2006. | | | 12 | Fixed charge ratios | | | 15 | Letter from independent registered public accounting firm | | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | | | JCP&LOE
| | | | | | | | 12 | Fixed charge ratios | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | 31.3 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | 32.2 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. |
| | | FirstEnergy
| | | | | | | 15 | Letter from independent registered public accounting firm | | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | | | OE and Penn
| | | | | | | 15 | Letter from independent registered public accounting firm | | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | | CEI | | | | | | | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | | | TE | | | | | | | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | | JCP&L | | | | | | 12 | Fixed charge ratios | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | 31.3 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | 32.2 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | | Met-Ed | | | | | | 12 | Fixed charge ratios | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | | Penelec | | | | | | 12 | Fixed charge ratios | | 15 | Letter from independent registered public accounting firm | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | | | * Three substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to three other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority and the Beaver County Industrial Development Authority relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp. (Form 8-K dated April 3, 2006) |
Pursuant to reporting requirements of respective financings, FirstEnergy, OE, 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.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
May 5, 2005
8, 2006
| | FIRSTENERGY CORP. | | | Registrant | | | | | | OHIO EDISON COMPANY | | | Registrant | | | | | | THE CLEVELAND ELECTRIC | | | ILLUMINATING COMPANY | | | Registrant | | | | | | THE TOLEDO EDISON COMPANY | | | Registrant | | | | | | PENNSYLVANIA POWER COMPANY | | | Registrant | | | | | | JERSEY CENTRAL POWER & LIGHT COMPANY | | | Registrant | | | | | | METROPOLITAN EDISON COMPANY | | | Registrant | | | | | | PENNSYLVANIA ELECTRIC COMPANY | | | Registrant |
| | | /s/ Harvey L. Wagner /s/
| | Harvey L. Wagner |
|
| Vice President, Controller
and Chief Accounting Officer | | | | Harvey L. Wagner | | | Vice President, Controller | | and Chief Accounting Officer |
|