| 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 for Nonmonetary Transactions" | | ARB | Accounting Research Bulletin | | ARB 43 | ARB No. 43, "Restatement and Revision of Accounting Research Bulletins" | | ARO | Asset Retirement Obligation | | B&W | Babcock & Wilcox Company | | BGS | Basic Generation Service | | BTU | British Thermal Unit | | CAIDI | Customer Average Interruption Duration Index | | CAIR | Clean Air Interstate Rule | | CAL | Confirmatory Action Letter | | CAMR | Clean Air Mercury Rule | | CBP | Competitive Bid Process | | CIEP | Commercial Industrial Energy Price | CO2 | Carbon Dioxide | | CTC | Competitive Transition Charge | | DCPD | Deferred Compensation Plan for Outside Directors | | DIG C20 | Derivatives Implementation Group Issue No. C20, “Scope Exceptions: Interpretations of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature” | | DOJ | United States Department of Justice |
GLOSSARY OF TERMS, Cont'd.
| DRA | Division of the Ratepayer Advocate | | ECAR | East Central Area Reliability Coordination Agreement | | EDCP | Executive Deferred Compensation Plan | | 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 Same
Counterparty" | EITF 99-19 | EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent" | | EPA | Environmental Protection Agency | | EPACT | Energy Policy Act of 2005 | | ERO | Electric Reliability Organization | | ESOP | Employee Stock Ownership Plan | | FASB | Financial Accounting Standards Board | | FERC | Federal Energy Regulatory Commission | | FIN | FASB Interpretation | FIN 46R46(R) | FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" | | FIN 46(R)-6 | FIN 46(R)-6, “Determining the Variability to be Considered in Applying FASB interpretation No. 46(R)” | | FIN 47 | FASB InterpretationFIN 47, "Accounting for Conditional Asset Retirement Obligations - an
interpretation of FASB Statement No. 143" | | FIN 48 | FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No.109” | | 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"
| FSP 109-1 | FASB Staff Position No. 109-1, "Application of FASB Statement No. 109, Accounting for Income
| | Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs | | Creation 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 | | LTIP | Long-Term Incentive Program | | 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 | | NOPR | Notice of Proposed Rulemaking | | NOV | Notices of Violation | NOX | 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 | OPAE | Ohio Partners for Affordable Energy | | OPEB | Other Post-Employment Benefits | | OSBA | Office of Small Business Advocate | | OTS | Office of Trial Staff | | PaDEP | Pennsylvania Department of Environmental Protection | | PCAOB | Public Company Accounting Oversight Board (United States) | PCRBsPICA | Pollution Control Revenue BondsPenelec 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 | PSA | Purchase and Sale Agreement | | 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 | | RTOR | Through and Out Rates | | 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 | | SECA | Seams Elimination Cost Adjustment | | 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" | | 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 153 | SFAS No. 153, "Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29" | SFAS 154 | SFAS No. 154, "Accounting Changes and Error Corrections - a replacement of APB Opinion No.
20 and FASB Statement No. 3"
| SO2 | Sulfur Dioxide | | SRM | Special Reliablity Master | | TBC | Transition Bond Charge | | TMI-2 | Three Mile Island Unit 2 | | VIE | Variable Interest Entity | | VMEP | Vegetation Management Enhancement Project |
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)
11. - 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 six monthsand second quarters of 2005 have been classified as discontinued operations on the Consolidated Statements of Income (see Note 6)4). As discussed in Note 16,13, 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 11)9) when it anticipates absorbing a majority ofis determined to be the VIE’s gains or losses. If no entity absorbs a majority of the VIE’s gains or losses, FirstEnergy consolidates a VIE when it expects to receive a majority of the VIE’s residual return.VIE's primary beneficiary. Investments in nonconsolidated affiliates which are not deemed to be VIEs 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 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 in Fuel and purchased power or energy sale in Unregulated businesses, respectively, in the Consolidated Statements of Income. 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 accounted for those 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 Task Force will 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. At its June 2005 meeting, the Task Force agreed to propose for public comment a framework for evaluating transactions within the scope of EITF 04-13. The proposed framework is based on the principle that two or more transactions with the same counterparty should be viewed as a single transaction when the transactions are entered into in contemplation of one another. If the EITF were to determine that transactions such as FES' purchases and sales in the PJM Market should be accounted for as single nonmonetary transactions, the transition provisions for the EITF may require or permit FES to 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 $283 million and $564 million for the three months and six months ended June 30, 2004, respectively.
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 increases of $3.1 million (CEI - $1.9 million, OE - $0.6 million, Penn - $0.1 million, TE - $0.3 million, FGCO - $0.2 million) and $9.0 million (CEI - $4.0 million, OE - $3.9 million, Penn - $0.2 million, TE - $0.8 million, FGCO - $0.1 million) in income before discontinued operations and net income ($0.01and $0.03 per share of common stock) during the three and six months ended June 30, 2005, respectively.
42. - 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 sharesThe following table reconciles the computation of common stock totaling 3.3 million in the three monthsbasic and six months ended June 30, 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 and six months ended June 30, 2005. The following table reconciles the denominators for basic and diluted earnings per share from Income Before Discontinued Operations:before discontinued operations:
| | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | Reconciliation of Basic and Diluted Earnings per Share | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In thousands, except per share amounts) | | | | | | | | | | | | | | | | | | Income Before Discontinued Operations | | $ | 178,765 | | $ | 201,860 | | $ | 319,795 | | $ | 374,209 | | | | | | | | | | | | | | | | | | Average Shares of Common Stock Outstanding: | | | | | | | | | | | | | | | Denominator for basic earnings per share | | | | | | | | | | | | | | | (weighted average shares outstanding) | | | 328,063 | | | 327,284 | | | 327,986 | | | 327,171 | | | | | | | | | | | | | | | | | | Assumed exercise of dilutive stock options and awards | | | 1,816 | | | 1,819 | | | 1,693 | | | 1,890 | | | | | | | | | | | | | | | | | | Denominator for diluted earnings per share | | | 329,879 | | | 329,103 | | | 329,679 | | | 329,061 | | | | | | | | | | | | | | | | | | Income Before Discontinued Operations per Common Share: | | | | | | | | | | | | | | | Basic | | | $0.54 | | | $0.61 | | | $0.98 | | | $1.15 | | | Diluted | | | $0.54 | | | $0.61 | | | $0.97 | | | $1.14 | |
| | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | Reconciliation of Basic and Diluted Earnings per Share | | 2006 | | 2005 | | 2006 | | 2005 | | | | | (In millions, except per share amounts) | | | | | | | | | | | | | | | | | | Income Before Discontinued Operations | | $ | 304 | | $ | 179 | | $ | 525 | | $ | 320 | | | Less: Redemption premium on subsidiary preferred stock | | | (3 | ) | | - | | | (3 | ) | | - | | | Earnings on Common Stock Before Discontinued Operations | | $ | 301 | | $ | 179 | | $ | 522 | | $ | 320 | | | | | | | | | | | | | | | | | Weighted Average Shares of Common Stock Outstanding: | | | | | | | | | | | | | | | Denominator for basic earnings per share | | | 328 | | | 328 | | | 328 | | | 328 | | | Assumed exercise of dilutive stock options and awards | | | 2 | | | 2 | | | 2 | | | 2 | | | Denominator for diluted earnings per share | | | 330 | | | 330 | | | 330 | | | 330 | | | | | | | | | | | | | | | | | | Earnings Before Discontinued Operations per Common Share: | | | | | | | | | | | | | | | Basic | | $ | 0.92 | | $ | 0.54 | | $ | 1.59 | | $ | 0.98 | | | Diluted | | $ | 0.91 | | $ | 0.54 | | $ | 1.58 | | $ | 0.97 | | | | | | | | | | | | | | | |
53. - GOODWILL
FirstEnergy's goodwill primarily relates to its regulated services segment. In the three and six months ended June 30, 2005,2006, FirstEnergy adjusted goodwill related to the divestiture of a non-core operations (FES' natural gas business, MYR subsidiary, Power Piping Company, and a portion of itsasset (62% 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 resultbenefit that had been reserved in purchase accounting. Adjustments to goodwill in the second quarter of property tax settlements. FirstEnergy estimates that completion of transition cost recovery (see Note 14) will not result in an impairment of goodwill relating2006 were immaterial. The following table reconciles changes to its regulated business segment. A summary of the changes in goodwill for the three months and six months ended June 30, 2005 is shown below.2006.
Three Months Ended | | FirstEnergy | | CEI | | TE | | JCP&L | | Met-Ed | | Penelec | | | | | (In millions) | | | | | | | | | | | | | | | | | | Balance as of April 1, 2005 | | $ | 6,034 | | $ | 1,694 | | $ | 505 | | $ | 1,984 | | $ | 868 | | $ | 887 | | | Non-core asset sales | | | (1 | ) | | - | | | - | | | - | | | - | | | - | | | Balance as of June 30, 2005 | | $ | 6,033 | | $ | 1,694 | | $ | 505 | | $ | 1,984 | | $ | 868 | | $ | 887 | |
Six Months Ended | | 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 | | | (13 | ) | | - | | | - | | | - | | | - | | | - | | | Adjustments related to GPU acquisition | | | (4 | ) | | - | | | - | | | (1 | ) | | (2 | ) | | (1 | ) | | Balance as of June 30, 2005 | | $ | 6,033 | | $ | 1,694 | | $ | 505 | | $ | 1,984 | | $ | 868 | | $ | 887 | |
Goodwill Reconciliation | | 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 June 30, 2006 | | $ | 5,940 | | $ | 1,688 | | $ | 501 | | $ | 1,978 | | $ | 860 | | $ | 878 | |
64. - DIVESTITURES AND DISCONTINUED OPERATIONS
In December 2004, FES' natural gas business qualified as assets held for saleMarch 2006, FirstEnergy sold 60% of its interest in accordance with SFAS 144. On March 31, 2005, FES completed the saleMYR for an after-tax gain of $5$0.2 million. In June 2006, FirstEnergy sold an additional 1.67% interest. As a result of the March sale, FirstEnergy deconsolidated MYR in the first quarter of 2006 and accounts for its remaining 38.33% interest under the equity method. In March 2005, FirstEnergy sold 51% of its interest in FirstCom resulting infor an after-tax gain of $4 million. FirstEnergy accounts for its remaining 31.85% interest in FirstCom onunder the equity basis.method.
During the first six months of 2005, FirstEnergy sold certain of itsthree FSG subsidiaries (Cranston, Elliott-Lewis Spectrum and Cranston,Spectrum), an MYR subsidiary (Power Piping) and MYR’s Power Piping Company subsidiary,FES' retail natural gas business, resulting in anaggregate after-tax gaingains of $12$17 million. FSG'sThe remaining FSG subsidiaries continue to be actively marketed and qualify as assets held for sale in accordance with SFAS 144 and are expected to be recognized as completed sales beforebecause FirstEnergy anticipates that the end of 2005. The assets and liabilitiestransfer of these remaining FSG subsidiaries are not material to FirstEnergy’s Consolidated Balance Sheetassets, with a net carrying value of $48 million as of June 30, 2005,2006, will qualify for recognition as completed sales within one year. As of June 30, 2006, the FSG subsidiaries classified as held for sale did not meet the criteria for discontinued operations. The carrying amounts of FSG's assets and thereforeliabilities held for sale are not material and have 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 results (including the gains on sales of assets discussed above) for Cranston, Elliott-Lewis, Cranston, Power Piping and FES' retail natural gas business of $(1) million and $18 million for the three months and six months ended June 30, 2005, respectively, and $2 million and $4 million for the three and six months ended June 30, 2004, respectively, are reported as discontinued operations on FirstEnergy's Consolidated Statements of Income. Pre-tax operating results for these entities were $(2) million and $2 million for the three months and six months ended June 30, 2005, respectively, and $4 million and $7 million for the three and six months ended June 30, 2004, respectively. Revenues associated with discontinued operations for the three months and six months ended June 30, 2005 were $11 million and $206 million, respectively, and for the three and six months ended June 30, 2004 were $158 million and $357 million, respectively. As of June 30, 2005, the remaining FSG businesses do not meet the criteria for discontinued operations; therefore, the net results ($(3) million and $(4) million for the three and six months ended June 30, 2005, respectively, and $0.3 million and $(1) million for the three and six months ended June 30, 2004, respectively) from these subsidiaries have been included in continuing operations. See Note 16 for FSG's segment financial information.
The following table summarizes the sources of income (loss) from discontinued operations.operations for the three months and six months ended June 30, 2005:
| | | Three Months Ended | | Six Months Ended | | | Three Months | | | Six Months | | | | | June 30, | | June 30, | | | (In millions) | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | | (In millions) | | | Discontinued operations (net of tax) | | | | | | | | | | | | | | | | Discontinued Operations (Net of tax) | | | | | | | | Gain on sale: | | | | | | | | | | | | | | | | | | | | Natural gas business | | $ | - | | $ | - | | $ | 5 | | $ | - | | | $ | - | | $ | 5 | | FSG and MYR subsidiaries | | | - | | | - | | | 12 | | | - | | | | - | | | 12 | | Reclassification of operating income | | | (1 | ) | | 2 | | | 1 | | | 4 | | | | Reclassification of operating income (loss) | | | | (1 | ) | | 1 | | | Total | | $ | (1 | ) | $ | 2 | | $ | 18 | | $ | 4 | | | $ | (1 | ) | $ | 18 | | | | | | | | | | | | | | | | | |
75. - DERIVATIVE INSTRUMENTS
FirstEnergy is 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, and to a lesser extent, for trading purposes. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughoutactivities. The Committee is responsible for promoting the Company.effective design and implementation of sound risk management programs and oversees 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 unless they meet the normal purchase and normal sales criteria.exception criterion. Derivatives that meet that criterion are accounted for on the accrual basis. The changes in the fair value of a derivative instrumentinstruments that do not meet the normal purchase and sales criterion are recorded in current earnings, in other comprehensive income,AOCL, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, and on the nature of the hedge transaction.
FirstEnergy has entered into fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received,transaction and interest payment dates match those of the underlying debt obligations. During the second quarter, FirstEnergy unwound swaps with a total notional amount of $350 million from which it received $17 million in cash gains. The gains will be recognized over the remaining maturity of each respective hedged security as reduced interest expense. As of June 30, 2005, the aggregate notional value of interest rate swap agreements outstanding was $1.4 billion.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 impact of ineffectiveness on earnings during the three and six months ended June 30, 2005 was not material.
The net deferred losslosses of $93$30 million included in AOCL as of June 30, 2005,2006, for derivative hedging activity, as compared to the December 31, 20042005 balance of $92$78 million of net deferred losses, resulted from a $4net $35 million increasedecrease related to current hedging activity a $4 million increase due to the sale of gas business contracts and a $7$13 million decrease due to net hedge losses included in earnings during the six months ended June 30, 2005.2006. Approximately $16$9 million (after tax) of the net deferred losslosses on derivative instruments in AOCL as of June 30, 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 six months 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 June 30, 2006, the aggregate notional value of interest rate swap agreements outstanding was $750 million.
During 2005 and the first six months 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 subsidiaries 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. FirstEnergy revised the tenor and timing of its financing plan during the first six months of 2006. FirstEnergy terminated and revised its forward swaps, ultimately terminating swaps with an aggregate notional value of $600 million as its subsidiaries issued long term debt in the second quarter. As required by SFAS 133, FirstEnergy assessed the amount of ineffectiveness of the hedges at each termination. FirstEnergy received cash gains of $41 million, of which approximately $6 million ($4 million net of tax) was deemed ineffective and recognized in earnings in the first six months of 2006. The remaining gain deemed effective in the amount of approximately $35 million ($22 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 June 30, 2006, FirstEnergy had forward swaps with an aggregate notional amount of $550million and a long-term debt securities fair value of $29 million.
6. - STOCK BASED COMPENSATION
Effective January 1, 2006, FirstEnergy engagesadopted SFAS 123(R), which requires the expensing of stock-based compensation. 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 recognized in the trading of commodity derivatives and periodically experiences net open positions. FirstEnergy’s risk management policies limit the exposure to market risk from open positions and require daily reporting to management of potential financial exposures. During the threesecond quarter and six months ended June 30, 2005,2006 included the effectexpense for all share-based payments granted prior to but not yet vested as of discretionary trading on earnings wasJanuary 1, 2006. Results for prior periods were not material.restated.
8 - STOCK BASED COMPENSATION
FirstEnergy appliesPrior to the adoption of SFAS 123(R) on January, 1, 2006, FirstEnergy’s LTIP, EDCP, ESOP, and DCPD stock-based compensation programs were 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 material stock-based employeeprograms - restricted stock, restricted stock units, stock options and performance shares.
Under APB 25, no compensation expense iswas 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 SFAS 123(R), a revision to SFAS 123 which requires expensing the fair value of The pro forma effects on net income for stock options (see Note 15). 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 granted since the third quarter of 2004. Consequently, the impact of adopting SFAS 123(R) was not material to annual, rather than interim, periods that begin after June 15, 2005. FirstEnergy will be required to adopt this standard beginning January 1, 2006. The table below summarizes the effects on FirstEnergy’sFirstEnergy's net income and earnings per share had FirstEnergy appliedin the fair value recognition provisionssecond quarter and six months ended June 30, 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(R) on FirstEnergy's financial results, only condensed disclosure has been provided. Reference is made to stock-based employee compensation inFirstEnergy’s annual report on Form 10-K for the current reporting periods.year ended December 31, 2005 for expanded annual disclosure.
| | | | | Three Months Ended | | Six Months Ended | | | | | | | June 30, | | June 30, | | | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | | | (In thousands, except per share amounts) | | | | | | | | | | | | | | | | Net income, as reported | | | | | $ | 177,992 | | $ | 204,045 | | $ | 337,718 | | $ | 378,044 | | | | | | | | | | | | | | | | | | | | | Add back compensation expense | | | | | | | | | | | | | | | | | | reported in net income, net of tax | | | | | | | | | | | | | | | | | | (based on APB 25)* | | | | | | 14,413 | | | 9,112 | | | 22,381 | | | 15,806 | | | | | | | | | | | | | | | | | | | | | Deduct compensation expense based | | | | | | | | | | | | | | | | | | upon estimated fair value, net of tax | | | | | | (15,656 | ) | | (13,882 | ) | | (26,493 | ) | | (24,829 | ) | | | | | | | | | | | | | | | | | | | | Pro forma Net income | | | | | $ | 176,749 | | $ | 199,275 | | $ | 333,606 | | $ | 369,021 | | | | | | | | | | | | | | | | | | | | | Earnings Per Share of Common Stock - | | | | | | | | | | | | | | | | | | Basic | | | | | | | | | | | | | | | | | | As reported | | | | | | $0.54 | | | $0.62 | | | $1.03 | | | $1.16 | | | Pro forma | | | | | | $0.54 | | | $0.61 | | | $1.02 | | | $1.13 | | | Diluted | | | | | | | | | | | | | | | | | | As reported | | | | | | $0.54 | | | $0.62 | | | $1.02 | | | $1.15 | | | Pro forma | | | | | | $0.54 | | | $0.61 | | | $1.01 | | | $1.12 | | | | | * Includes restricted stock, restricted stock units, stock options, performance shares, Employee Stock Ownership Plan, Executive Deferred Compensation Plan and Deferred Compensation Plan for Outside Directors. | |
| | Three Months | | Six Months | | | | (In millions, except per share amounts) | | | | | | | | | | | Net Income, as reported | | $ | 178 | | $ | 338 | | | | | | | | | | | Add back compensation expense | | | | | | | | reported in net income, net of tax (based on | | | | | | | | APB 25)* | | | 14 | | | 22 | | | | | | | | | | | Deduct compensation expense based | | | | | | | | upon estimated fair value, net of tax* | | | (17 | ) | | (28 | ) | | | | | | | | | | Pro forma net income | | $ | 175 | | $ | 332 | | | Earnings Per Share of Common Stock - | | | | | | | | Basic | | | | | | | | As Reported | | $ | 0.54 | | $ | 1.03 | | ProForma | | $ | 0.53 | | $ | 1.01 | | Diluted | | | | | | | | As Reported | | $ | 0.54 | | $ | 1.02 | | Pro Forma | | $ | 0.53 | | $ | 1.01 | |
FirstEnergy reduced the use of*Includes restricted stock, restricted stock units, stock options, performance
shares, ESOP, EDCP and increased the use of performance-based, restricted stock units. Therefore, the pro forma effects of applying SFAS 123(R) may not be representative of its future effect. FirstEnergy does not expect to accelerate out-of-the-money options in anticipation of implementing SFAS 123(R) on January 1, 2006 (see Note 15).DCPD.
97. - 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 six months ended June 30, 2005, the impact on earnings would have been immaterial.
The ARO liability of $1.1$1.2 billion as of June 30, 2005 included $1.1 billion for2006 primarily relates 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 utilizeduses 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 June 30, 2005,2006, the fair value of the decommissioning trust assets was $1.6$1.8 billion.
The following tables analyze changes to the ARO balances during the three months and six months ended June 30, 2006 and 2005, respectively.
Three Months Ended | | FirstEnergy | | OE | | CEI | | TE | | Penn | | JCP&L | | Met-Ed | | Penelec | | | | | (In millions) | | ARO Reconciliation | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance, April 1, 2006 | | $ | 1,148 | | $ | 84 | | $ | 8 | | $ | 25 | | $ | - | | $ | 81 | | $ | 144 | | $ | 73 | | | Liabilities incurred | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Liabilities settled | | | (6 | ) | | - | | | (6 | ) | | - | | | - | | | - | | | - | | | - | | | Accretion | | | 18 | | | 1 | | | - | | | 1 | | | - | | | 1 | | | 2 | | | 1 | | | Revisions in estimated | | | | | | | | | | | | | | | | | | | | | | | | | | | cashflows | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Balance, June 30, 2006 | | $ | 1,160 | | $ | 85 | | $ | 2 | | $ | 26 | | $ | - | | $ | 82 | | $ | 146 | | $ | 74 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance, April 1, 2005 | | $ | 1,095 | | $ | 204 | | $ | 276 | | $ | 198 | | $ | 141 | | $ | 74 | | $ | 135 | | $ | 67 | | | Liabilities incurred | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Liabilities settled | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Accretion | | | 18 | | | 4 | | | 5 | | | 3 | | | 2 | | | 1 | | | 2 | | | 1 | | | Revisions in estimated | | | | | | | | | | | | | | | | | | | | | | | | | | | cashflows | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Balance, June 30, 2005 | | $ | 1,113 | | $ | 208 | | $ | 281 | | $ | 201 | | $ | 143 | | $ | 75 | | $ | 137 | | $ | 68 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Six Months Ended | | FirstEnergy | | OE | | CEI | | TE | | Penn | | JCP&L | | Met-Ed | | Penelec | | | | | (In millions) | | ARO Reconciliation | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance, January 1, 2006 | | $ | 1,126 | | $ | 83 | | $ | 8 | | $ | 25 | | $ | - | | $ | 80 | | $ | 142 | | $ | 72 | | | Liabilities incurred | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Liabilities settled | | | (6 | ) | | - | | | (6 | ) | | - | | | - | | | - | | | - | | | - | | | Accretion | | | 36 | | | 2 | | | - | | | 1 | | | - | | | 2 | | | 4 | | | 2 | | | Revisions in estimated | | | | | | | | | | | | | | | | | | | | | | | | | | | cashflows | | | 4 | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Balance, June 30, 2006 | | $ | 1,160 | | $ | 85 | | $ | 2 | | $ | 26 | | $ | - | | $ | 82 | | $ | 146 | | $ | 74 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance, January 1, 2005 | | $ | 1,078 | | $ | 201 | | $ | 272 | | $ | 195 | | $ | 138 | | $ | 72 | | $ | 133 | | $ | 67 | | | Liabilities incurred | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Liabilities settled | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Accretion | | | 35 | | | 7 | | | 9 | | | 6 | | | 5 | | | 3 | | | 4 | | | 1 | | | Revisions in estimated | | | | | | | | | | | | | | | | | | | | | | | | | | | cashflows | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Balance, June 30, 2005 | | $ | 1,113 | | $ | 208 | | $ | 281 | | $ | 201 | | $ | 143 | | $ | 75 | | $ | 137 | | $ | 68 | |
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 following tables provide the beginning and ending aggregate carrying amount of the ARO and the changes to the balance during the three and six months ended June 30, 2005 and 2004, respectively.
Three Months Ended | | FirstEnergy | | OE | | CEI | | TE | | Penn | | JCP&L | | Met-Ed | | Penelec | | | | | (In millions) | | ARO Reconciliation | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance, April 1, 2005 | | $ | 1,095 | | $ | 204 | | $ | 276 | | $ | 198 | | $ | 141 | | $ | 74 | | $ | 135 | | $ | 67 | | | Liabilities incurred | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Liabilities settled | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Accretion | | | 18 | | | 4 | | | 5 | | | 3 | | | 2 | | | 1 | | | 2 | | | 1 | | | Revisions in estimated | | | | | | | | | | | | | | | | | | | | | | | | | | | cash flows | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Balance June 30, 2005 | | $ | 1,113 | | $ | 208 | | $ | 281 | | $ | 201 | | $ | 143 | | $ | 75 | | $ | 137 | | $ | 68 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance, April 1, 2004 | | $ | 1,198 | | $ | 191 | | $ | 259 | | $ | 185 | | $ | 132 | | $ | 111 | | $ | 213 | | $ | 107 | | | Liabilities incurred | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Liabilities settled | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Accretion | | | 19 | | | 3 | | | 4 | | | 3 | | | 2 | | | 2 | | | 3 | | | 2 | | | Revisions in estimated | | | | | | | | | | | | | | | | | | | | | | | | | | | cash flows | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Balance June 30, 2004 | | $ | 1,217 | | $ | 194 | | $ | 263 | | $ | 188 | | $ | 134 | | $ | 113 | | $ | 216 | | $ | 109 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Six Months Ended | | FirstEnergy | | OE | | CEI | | TE | | Penn | | JCP&L | | Met-Ed | | Penelec | | | | | (In millions) | | ARO Reconciliation | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance, January 1, 2005 | | $ | 1,078 | | $ | 201 | | $ | 272 | | $ | 195 | | $ | 138 | | $ | 72 | | $ | 133 | | $ | 67 | | | Liabilities incurred | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Liabilities settled | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Accretion | | | 35 | | | 7 | | | 9 | | | 6 | | | 5 | | | 3 | | | 4 | | | 1 | | | Revisions in estimated | | | | | | | | | | | | | | | | | | | | | | | | | | | cash flows | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Balance June 30, 2005 | | $ | 1,113 | | $ | 208 | | $ | 281 | | $ | 201 | | $ | 143 | | $ | 75 | | $ | 137 | | $ | 68 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance, January 1, 2004 | | $ | 1,179 | | $ | 188 | | $ | 255 | | $ | 182 | | $ | 130 | | $ | 109 | | $ | 210 | | $ | 105 | | | Liabilities incurred | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Liabilities settled | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Accretion | | | 38 | | | 6 | | | 8 | | | 6 | | | 4 | | | 4 | | | 6 | | | 4 | | | Revisions in estimated | | | | | | | | | | | | | | | | | | | | | | | | | | | cash flows | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | Balance June 30, 2004 | | $ | 1,217 | | $ | 194 | | $ | 263 | | $ | 188 | | $ | 134 | | $ | 113 | | $ | 216 | | $ | 109 | |
10 - PENSION AND OTHER POSTRETIREMENT BENEFITS:
The components of FirstEnergy's net periodic pension cost and other postretirement benefit costcosts (including amounts capitalized) for the three months and six months ended June 30, 20052006 and 2004,2005 consisted of the following:
| | | Three Months Ended | Six Months Ended | | | Three Months Ended | Six Months Ended | | | | | June 30, | | June 30, | | | June 30, | | June 30, | | Pension Benefits | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | | | | | (In millions) | | | Service cost | | $ | 19 | | $ | 19 | | $ | 38 | | $ | 39 | | | $ | 21 | | $ | 19 | | $ | 41 | | $ | 38 | | | Interest cost | | | 64 | | | 63 | | | 128 | | | 126 | | | | 66 | | | 64 | | 133 | | | 128 | | | Expected return on plan assets | | | (86 | ) | | (71 | ) | | (173 | ) | | (143 | ) | | | (99 | ) | | (86 | ) | | (198 | ) | | (173 | ) | | Amortization of prior service cost | | | 2 | | | 2 | | | 4 | | | 4 | | | | 2 | | | 2 | | 5 | | | 4 | | | Recognized net actuarial loss | | | 9 | | | 10 | | | 18 | | | 20 | | | | 15 | | | 9 | | | 29 | | | 18 | | | Net periodic cost | | $ | 8 | | $ | 23 | | $ | 15 | | $ | 46 | | | $ | 5 | | $ | 8 | | $ | 10 | | $ | 15 | |
| | | Three Months Ended | Six Months Ended | | | | | June 30, | | June 30, | | Other Postretirement Benefits | | 2006 | | 2005 | | 2006 | | 2005 | | | | | (In millions) | | | Service cost | | $ | 9 | | $ | 10 | | $ | 17 | | $ | 20 | | | Interest cost | | | 26 | | | 27 | | | 52 | | | 55 | | | Expected return on plan assets | | | (12 | ) | | (11 | ) | | (23 | ) | | (22 | ) | | Amortization of prior service cost | | | (19 | ) | | (11 | ) | | (37 | ) | | (22 | ) | | Recognized net actuarial loss | | | 14 | | | 10 | | | 27 | | | 20 | | | Net periodic cost | | $ | 18 | | $ | 25 | | $ | 36 | | $ | 51 | |
| | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | Other Postretirement Benefits | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In millions) | | | Service cost | | $ | 10 | | $ | 8 | | $ | 20 | | $ | 19 | | | Interest cost | | | 27 | | | 25 | | | 55 | | | 56 | | | Expected return on plan assets | | | (11 | ) | | (10 | ) | | (22 | ) | | (22 | ) | | Amortization of prior service cost | | | (11 | ) | | (8 | ) | | (22 | ) | | (19 | ) | | Recognized net actuarial loss | | | 10 | | | 9 | | | 20 | | | 20 | | | Net periodic cost | | $ | 25 | | $ | 24 | | $ | 51 | | $ | 54 | |
Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The CompaniesFirstEnergy’s subsidiaries 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 and six months ended June 30, 20052006 and 20042005 were as follows:
| | | Three Months Ended | | Six Months Ended | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | June 30, | | June 30, | | Pension Benefit Cost (Credit) | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | | | | | (In millions) | | | OE | | $ | 0.2 | | $ | 1.8 | | $ | 0.4 | | $ | 3.5 | | | $ | (1.1 | ) | $ | 0.2 | | $ | (2.1 | ) | $ | 0.4 | | | Penn | | | (0.2 | ) | | 0.1 | | (0.4 | ) | | 0.2 | | | | (0.4 | ) | | (0.2 | ) | | (0.8 | ) | | (0.4 | ) | | CEI | | | 0.3 | | 1.6 | | 0.7 | | 3.2 | | | | 1.0 | | | 0.3 | | 1.9 | | | 0.7 | | | TE | | | 0.3 | | 0.8 | | 0.6 | | 1.6 | | | | 0.2 | | | 0.3 | | 0.4 | | | 0.6 | | | JCP&L | | | (0.3 | ) | | 1.9 | | (0.5 | ) | | 3.7 | | | | (1.4 | ) | | (0.3 | ) | | (2.7 | ) | | (0.5 | ) | | Met-Ed | | | (1.1 | ) | | - | | (2.2 | ) | | 0.1 | | | | (1.7 | ) | | (1.1 | ) | | (3.5 | ) | | (2.2 | ) | | Penelec | | | (1.3 | ) | | 0.1 | | (2.7 | ) | | 0.2 | | | | (1.3 | ) | | (1.3 | ) | | (2.7 | ) | | (2.7 | ) | | Other FirstEnergy subsidiaries | | | | 9.9 | | | 9.6 | | | 20.0 | | | 19.1 | | | | | $ | 5.2 | | $ | 7.5 | | $ | 10.5 | | $ | 15.0 | |
| | | Three Months Ended | | Six Months Ended | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | June 30, | | June 30, | | Other Postretirement Benefit Cost | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | | | | | (In millions) | | | OE | | $ | 5.8 | | $ | 4.9 | | $ | 11.5 | | $ | 12.0 | | | $ | 3.4 | | $ | 5.8 | | $ | 6.8 | | $ | 11.5 | | | Penn | | | 1.2 | | 1.0 | | 2.4 | | 2.5 | | | | 0.8 | | | 1.2 | | | 1.6 | | | 2.4 | | | CEI | | | 3.8 | | 3.6 | | 7.6 | | 9.2 | | | | 2.8 | | | 3.8 | | | 5.5 | | | 7.6 | | | TE | | | 2.2 | | 1.3 | | 4.3 | | 3.4 | | | | 2.0 | | | 2.2 | | | 4.0 | | | 4.3 | | | JCP&L | | | 1.5 | | 0.9 | | 4.2 | | 2.5 | | | | 0.6 | | | 1.5 | | | 1.2 | | | 4.2 | | | Met-Ed | | | 0.4 | | 0.5 | | 0.8 | | 1.8 | | | | 0.7 | | | 0.4 | | | 1.5 | | | 0.8 | | | Penelec | | | 2.0 | | 0.4 | | 4.0 | | 1.8 | | | | 1.8 | | | 2.0 | | | 3.6 | | | 4.0 | | | Other FirstEnergy subsidiaries | | | | 6.1 | | | 8.1 | | | 12.1 | | | 16.2 | | | | | $ | 18.2 | | $ | 25.0 | | $ | 36.3 | | $ | 51.0 | |
119. - 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 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 leasebacksale-leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $663$640 million, $101$98 million and $531$498 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 relates primarily to the above-market costs it incurs for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. As of June 30, 2006, the net above-market loss liability projected 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 $74 million. Purchased power costs from these entities during the three months and six months ended June 30, 20052006 and 20042005 are shown in the table below:following table: | Three Months Ended | | Six Months Ended | | | | June 30, | | June 30, | | | | 2006 | | 2005 | | 2006 | | 2005 | | (In millions) | | JCP&L | $ | 19 | | $ | 21 | | $ | 34 | | $ | 42 | | | Met-Ed | | 16 | | | 14 | | | 33 | | | 30 | | | Penelec | | 7 | | | 7 | | | 14 | | | 14 | | | Total | $ | 42 | | $ | 42 | | $ | 81 | | $ | 86 | |
| | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In millions) | | | | | | | | | | | | | | | | | JCP&L | | $ | 29 | | $ | 35 | | $ | 56 | | $ | 63 | | | Met-Ed | | | 14 | | | 9 | | | 30 | | | 25 | | | Penelec | | | 7 | | | 6 | | | 14 | | | 13 | | | Total | | $ | 50 | | $ | 50 | | $ | 100 | | $ | 101 | |
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 - OHIO TAX LEGISLATION
On June 30, 2005, the State of Ohio enacted new tax legislation that creates a new Commercial Activity Tax (CAT), which is based on qualifying "taxable gross receipts" and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax is effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and the personal property tax is phased-out over a four-year period at a rate of approximately 25% annually, beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005.
The increase to income taxes associated with the adjustment to net deferred taxes for the three and six months ended June 30, 2005 is summarized below (in millions):
| | | | | | OE | | $ | 36.0 | | | CEI | | | 7.5 | | | TE | | | 17.5 | | | Other FirstEnergy subsidiaries | | | 10.7 | | | Total FirstEnergy | | $ | 71.7 | |
Income tax expenses were reduced during the three and six months ended June 30, 2005 by the initial phase-out of the Ohio income-based franchise tax as summarized below (in millions):
| OE | | $ | 4.9 | | | CEI | | | 1.4 | | | TE | | | 0.5 | | | Other FirstEnergy subsidiaries | | | 0.8 | | | Total FirstEnergy | | $ | 7.6 | |
1310. - COMMITMENTS, GUARANTEES AND CONTINGENCIES: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 June 30, 2005,2006, outstanding guarantees and other assurances aggregatedtotaled approximately $2.4$3.5 billion and includedconsisting of contract guarantees ($1.11.9 billion), surety bonds ($0.30.1 billion) and LOCs ($1.01.5 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. SuchThe likelihood is remote that such parental guarantees amount to $0.9of $0.8 billion (included in the $1.1$1.9 billion discussed above) as of June 30, 2005 and the likelihood is remote that such guarantees 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 aan LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect asAs of June 30, 2005:2006, FirstEnergy's maximum exposure under these collateral provisions was $501 million.
| | | | | Total | | Collateral Paid | | Remaining | | Collateral Provisions | | | | Exposure | | Cash | | LOC | | Exposure | | | | | | | (In millions) | | | | | | | | | | | | | | | | | | | | Credit rating downgrade | | | | | $ | 367 | | $ | 141 | | $ | 18 | | $ | 208 | | | Adverse event | | | | | | 50 | | | - | | | 7 | | | 43 | | | Total | | | | | $ | 417 | | $ | 141 | | $ | 25 | | $ | 251 | | | | | | | | | | | | | | | | | | | |
Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $296$146 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. The following table includes information regarding the subsidiary companies and their respective financing arrangement.
| | | | | Financing Arrangement | | | | | Borrowing | | Subsidiary Company | | Parent Company | | Borrowing Capacity | | | Parent Company | | Capacity | | | | | | (In millions) | | | | (In millions) | | | OES Capital, Incorporated | | | OE | | $ | 170 | | | | OE | | $ | 170 | | | CFC | | | CEI | | | 200 | | | | Centerior Funding Corp. | | | | CEI | | | 200 | | | Penn Power Funding LLC | | | Penn | | | 25 | | | | Penn | | | 25 | | | Met-Ed Funding LLC | | | Met-Ed | | | 80 | | | | Met-Ed | | | 80 | | | Penelec Funding LLC | | | Penelec | | | 75 | | | | Penelec | | | 75 | | | | | | | | $ | 550 | | | | | | $ | 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 ($4736 million as of June 30, 2005)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 CompaniesFirstEnergy 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 changes 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 FirstEnergy accrues environmental liabilities only when they concludeit concludes that it is probable that they haveit has an obligation for such costs and can reasonably determineestimate the amount of such costs. Unasserted claims are reflected in the Companies’FirstEnergy’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
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 On December 1, 2005, FirstEnergy issued a comprehensive report to shareholders regarding air emissions regulations and will post the report onan assessment of its web site, www.firstenergycorp.com.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 EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006 alleging violations to various sections of the Clean Air Act. A meeting has been scheduled for August 8, 2006 to discuss the alleged violations with the EPA. 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. OnIn 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 SO2 and NOxX emissions, whereas ourits New Jersey fossil-fired generation facilitiesfacility 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. 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 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. OnIn 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 NOx Xemission 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 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. Pennsylvania has proposed a new rule to regulate mercury emissions from coal-fired power plants that does not provide a cap and trade approach as in CAMR, but rather follows a command and control approach imposing emission limits on individual sources. If adopted as proposed, Pennsylvania’s mercury regulation would deprive FirstEnergy of mercury emission allowances that were to be allocated to the Mansfield Plant under CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. The future cost of compliance with these regulations, if adopted and implemented as proposed, 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, including 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 in the form of a Consent Decree that was approved by the Court on July 11, 2005, and 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 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 toward environmentally beneficial projects, which include wind energy purchasepurchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties payablepaid by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized 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-hourKWH 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.
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 June 30, 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 $64$70 million (JCP&L - $46.8$55 million, CEI - $2.3$2 million, TE - $0.2 million, Met-Ed - $47,000 and other - $15.0subsidiaries- $13 million) as ofhave been accrued through June 30, 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 Division 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 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 June 30, 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 websiteWeb site (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. FirstEnergy is also is proceeding with the implementation of the 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 new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date.equipment. The 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, FirstEnergy companies also are defending six separate complaint cases before the PUCO is continuingrelating to review FirstEnergy’s 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.
Three substantially similar actions were filed in various Ohio State courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All threeoutage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. Two ofIn these cases were refiled at the PUCO, one in 2004 and another in 2005. In each, individual complainants—three in one case and four in the other—seek damages related to the outages and also seeksought to represent others as part of a class action. FirstEnergy has filed responsive pleadings to both cases. The PUCO has dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. BothThree other pending PUCO complaint cases are otherwise currently pending further proceedings. In addition to the two cases that were refiled at the PUCO, the Ohio Companies were namedfiled by various insurance carriers either in their own name 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 was filed on August 25, 2004 against FirstEnergysubrogees or in the New York State Supreme Court.name of their insured. In thiseach of these three cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, several plaintiffs in the New York City metropolitan area allege that they sufferedfrom 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 power outages. None of the plaintiffs2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy affiliate.company. The sixth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It is currently expected that this case will be summarily dismissed, although the Motion is still pending. 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 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. 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 that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed an amended complaint and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. These motions are pending. Additionally, on June 23, 2006, one of the insurance carrier complainants filed an appeal with the Ohio Supreme Court on October 22, 2004. No timetableover the PUCO’s denial of motion for a decisionrehearing on the issue of the admissibility of the Task Force Report and the dismissal of FirstEnergy Corp. as a respondent. Briefing is expected to be completed on this appeal by mid-September. It is unknown when the Supreme Court will rule on the appeal. No estimate of potential liability is available for any of these cases.
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. FirstEnergy's motion to dismiss the matter was denied on June 2, 2006. FirstEnergy has since filed an appeal, which is pending. A responsive pleading to this matter has been established byfiled. Also, the Court. No damage estimatecomplaint has been provided and thusamended to include an additional party. No estimate of potential liability has been undertaken in this matter. FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy were based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. The plaintiff has not been determined.appealed.
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 had 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 (not deductible for income tax purposes) which reduced FirstEnergy'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. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.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. On July 8, 2005, FENOC requested an additional 120 days to respond to the NOV. FirstEnergy accrued $2.0$2 million for the proposeda potential fine in 2004prior to 2005 and accrued the remaining liability for the proposed fine 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 have legal liability basedresponse to the NRC's NOV on the events surrounding Davis-Besse it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.head degradation to reflect the deferred prosecution agreement that FENOC had reached with the DOJ.
Effective July 1, 2005, the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens.
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 preceding two years.years and the licensee's failure to take prompt and corrective action. FENOC operates the Perry Nuclear Power Plant, which is currently owned and/or leased by OE, CEI, TE and Penn (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which will include owned portions of the plant).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 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. On May 26,September 28, 2005, the NRC heldsent a public meetingCAL to discuss its oversight ofFENOC describing commitments that FENOC had made to improve the performance at the Perry Plant. While the NRCPlant and stated that the plantCAL 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 safely,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 overall performance had not substantially improved sinceof the heightened inspectionfacility was initiated.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 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 now repealed 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 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. Both filings were consolidated for hearing and decision described above. 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. On May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s complaint and approving the related tariffs, thus affirming OE’s entitlement to recovery of its transition charges. The City of Huron filed an application for rehearing of the PUCO’s decision on June 9, 2006 and OE filed a memorandum in opposition to that application on June 19, 2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The City of Huron has 60 days from the denial of rehearing to appeal the PUCO’s decision. 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. 1411. - REGULATORY MATTERS: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. The 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)an 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 Stipulation that incorporates the final report of a Special Reliability Masteran SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation 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. The SRM completed his work and issued his final report to the NJBPU on June 1, 2006. A meeting was held between JCP&L and the NJBPU on June 29, 2006 to discuss the SRM’s final report. JCP&L filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.
In May 2004, The EPACT provides for the PPUCcreation 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 approving revised reliability benchmarkson rehearing on March 30, 2006, providing certain clarifications and standards, including revised benchmarks and standardsessentially affirming the rule.
The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC’s certification requirements for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filedthe ERO. The NERC made a Petition for Amendment of Benchmarksfiling with the PPUCFERC 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. The ERO filing was noticed on April 7, 2006 and comments and reply comments were filed in May, 26, 2004, dueJune and July 2006. On July 20, 2006, the FERC certified NERC as the ERO to their implementationimplement the provisions of automated outage management systems following restructuring. Evidentiary hearings have been scheduled for November 2005. FirstEnergy is unableSection 215 of the Federal Power Act. The FERC directed NERC to predictmake a compliance filing within ninety days addressing such issues as the outcomeregional delegation agreements.
On April 4, 2006, NERC also submitted a filing with the FERC 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. The reliability standards filing was noticed by the FERC on April 18, 2006. In that notice, the FERC announced its intent to issue a Notice of Proposed Rulemaking on the proposed reliability standards at a future date. On May 11, 2006, the FERC staff released a preliminary assessment that cited many deficiencies in the proposed reliability standards. The NERC and industry participants filed comments in response to the Staff’s preliminary assessment. The FERC held a technical conference on the proposed reliability standards on July 6, 2006. The chairman has indicated that the FERC intends to act on the proposed reliability standards by issuing a NOPR in September of this proceeding.year. Interested parties will be given the opportunity to comment on the NOPR. NERC has requested an effective date of January 1, 2007 for the proposed 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. On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security standards that replaced interim standards put in place in the wake of the September 11, 2001 terrorist attacks, and thirteen additional reliability standards. The security standards became effective on June 1, 2006, and the remaining standards will become effective throughout 2006 and 2007. NERC intends to file the standards with the FERC and relevant Canadian authorities for approval.
In November 2004,FirstEnergy believes it is in compliance with all current NERC reliability standards. However, it is expected that the PPUC approved a settlement agreement filed by Met-Ed, Penelec and PennFERC 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 addressed issues relatedall prudent costs incurred to a PPUC investigation into Met-Ed's, Penelec's and Penn's servicecomply with the new 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 distribution for the years 2005 through 2007. The settlement also outlines an expedited remediation process to address any alleged non-compliance with terms of the settlement and an expedited PPUC hearing process if remediation is unsuccessful.standards be recovered in rates.
OhioOHIO
On October 21, 2003 the Ohio Companies filed their 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 PUCOthe PUCO’s 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 the proceeding as well as the associated entries on rehearing.
The Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, On September 28, 2005, the Supreme Court of Ohio heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order with respect to the approval of the rate stabilization charge, approval of the shopping credits, the granting of interest on shopping credit incentive deferral amounts, and continuesapproval of the Ohio Companies' support of energy efficiency and economic development efforts. Other key componentsCompanies’ financial separation plan. It remanded one matter back to the PUCO for further consideration of the Rate Stabilization Plan includeissue as to whether the following:RSP, as adopted by the PUCO, provided for sufficient means for customer participation in the competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion for Reconsideration with the Supreme Court of Ohio which was denied by the Court on June 21, 2006. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation, requesting the PUCO to initiate a proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. Separately, the OCC and NOAC also submitted to the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket to address the Court’s concern.
The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. Major provisions of the RCP include:
| | ·● | AmortizationMaintaining 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 for transition costs being recoveredJanuary 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years; | | | | | ● | Adjusting the RTC extendsand extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for OE to as late as 2007; CEI to as late as mid-2009 and TE and as of December 31, 2010 for CEI; | | | | | ● | Reducing the deferred shopping incentive balances as of January 1, 2006 by up to as late as mid-2008; |
| · | Deferral$75 million for OE, $45 million for TE, and $85 million for CEI by accelerating the application of interest costs on theeach respective company's accumulated customer shopping incentives as newcost of removal regulatory assets;liability; and |
| · | Ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes. |
On May 27, 2005, the Ohio Companies filed an application with the PUCO to establish a generation rate adjustment rider under the Rate Stabilization Plan. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to the Ohio Companies' retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider is seeking to recover all costs above the baseline (approximately $93 million in 2006). Various parties including the OCC have intervened in this case. The Ohio Companies have received discovery requests from the OCC and the PUCO staff. A procedural schedule has been established by the PUCO, with a hearing scheduled for October 4, 2005.
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 Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may require the Ohio Companies to undertake, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for the Ohio Companies in 2004. 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.
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. As of June 30, 2005, the accumulated deferred cost balance totaled approximately $518 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 of the securitization of the deferred balance. JCP&L is in discussions with the NJBPU staff as a result of the stipulated settlement agreements (as further discussed below) which recommended that the NJBPU issue an order regarding JCP&L's application.
The 2003 NJBPU decision on JCP&L's base electric rate proceeding disallowed certain regulatory assets and provided for an interim return on equity of 9.5% on JCP&L's rate base. The decision ordered a Phase II proceeding in which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards and determine whether the expenditures and projects undertaken by JCP&L to increase its system's reliability are prudent and reasonable for rate recovery. Depending on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an interim motion and a supplemental and amended motion for rehearing and reconsideration of the 2003 NJBPU decision, respectively. 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.
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 requested an increase to the MTC deferred balance recovery of approximately $20 million annually.
On May 25, 2005, the NJBPU approved two stipulated settlement agreements. The first stipulation between JCP&L and the NJBPU staff resolves all of the issues associated with JCP&L's motion for reconsideration of the 2003 NJBPU order (Phase I Order). The second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase II proceeding. The stipulated settlements provide for, among other things, the following:
| · | An annual increase in distribution revenues of $23 million effective June 1, 2005, associated with the Phase I Order reconsideration; |
| · | An annual increase in distribution revenues of $36 million effective June 1, 2005, related to JCP&L's Phase II Petition; |
| · | An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its deferred cost balance; |
| · | An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and |
| ·● | A commitment by JCP&LRecovering increased fuel costs (compared to maintain a target level2002 baseline) of customer service reliability withup 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 reduction in JCP&L's authorized return on common equity to its previous level of 9.5% afterfuel recovery mechanism. OE, TE, and CEI may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the target is not met for two consecutive quarters. The authorized return on common equity would then be restored to 9.75% whenamount collected through the target is met for two consecutive quarters.fuel recovery mechanism. |
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. On January 10, 2006, the Ohio Companies filed a Motion for Clarification of the PUCO order approving the RCP. The Phase II stipulation included an agreementOhio 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 revenues increase reflects a three-year amortization of JCP&L's service reliability improvement costs incurred in 2003-2005. This resultedexpenditures originally included in the creationrevised stipulation fall within the PUCO order definition of a regulatory asset associated withqualified expenditures. On January 25, 2006, the accelerated tree trimming costs which were expensedPUCO issued an Entry on Rehearing granting in 2003part, and 2004.denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The establishment ofPUCO granted the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million ($0.05 per share of common stock) in the second quarter of 2005.Ohio Companies’ requests to:
JCP&L sells all self-supplied energy (NUGs and owned generation) | ● | 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 wholesale market with offsetting credits to its deferred energy balanceapplications for rehearing on February 8, 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 notices of appeal with the exceptionSupreme Court of 300 MWOhio alleging various errors made by the PUCO in its order approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO and the Ohio Companies. The Appellees’ Merit Briefs are due on August 4, 2006. Appellants’ Reply Briefs will then be due on August 24, 2006.
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 recovered from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order. New BGS tariffs reflectingJanuary 1 through June 30, 2006 were approximately $61 million. That amount included the resultsrecovery of a Februaryportion of the 2005 auction fordeferred MISO expenses as described below. On May 1, 2006, the BGS supply became effectiveOhio Companies filed a modification to the rider to determine revenues ($141 million) 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 October 1, 2003 through December 31, 2005. On May 5,18, 2005, the NJBPU issued an order that BGS procurement proposals for post transition year four be filed by July 1, 2005. The NJBPU requested thatPUCO granted the filings address transmission rate issues and rate design alternatives. JCP&L filed its proposal on July 1, 2005. The auction is scheduled to take place in February 2006accounting authority for the supplyOhio 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 beginning June 1, 2006.
In accordance with an April 28,December 30, 2004 NJBPU order, JCP&L filed testimonythrough 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 June 7, 2004 supporting a continuationthe deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. On January 20, 2006, the OCC sought rehearing of the current level and durationPUCO’s approval of the fundingrecovery of TMI-2 decommissioningdeferred costs by New Jersey customers withoutthrough 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. On March 27, 2006, the OCC filed a reduction, termination or cappingmotion 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 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.rider recovery mechanism. On March 18, 2005, JCP&L filed20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of the Ohio Companies' case with a responsesimilar case involving Dayton Power & Light Company. Oral arguments were heard on May 10, 2006. The Ohio Companies are unable to those comments. A schedule for further proceedings has not yet been set.predict when a decision may be issued.
PennsylvaniaPENNSYLVANIA
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 werebecame effective in 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. Met-Ed’s and Penelec’s combined portion of total net merger savings during 2001 - 2004 is estimated to be approximately $31.5$51 million. A procedural schedule was established by the ALJ on January 17, 2006 and the companies filed initial testimony on March 1, 2006. On April 13, 2005, the Commonwealth Court issued an interim order in the remand proceeding that the parties should report the status of the negotiations toMay 4, 2006, the PPUC consolidated this proceeding with a copythe April 10, 2006 comprehensive rate filing proceeding discussed below. Met-Ed and Penelec are unable to predict the ALJ. The parties exchanged settlement proposals in May and June 2005 and continue to have settlement discussions.outcome of this matter.
In an October 16, 2003 order, the PPUC approved JuneSeptember 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 judge,Commonwealth Court, a Petition for Review of the PPUC's October 2 and October 16, 2003 Orders, and an applicationApplication for reargument,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 were held on June 8, 2006. On July 19, 2006, the Commonwealth Court issued its decision affirming the PPUC’s prior orders. Although the decision denied the appeal of Met-Ed and Penelec, they had previously accounted for the treatment of costs required by the PPUC’s October 2003 orders. As of June 30, 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 were $335 million and $57 million, respectively. Penelec's $57 million is subject to the pending resolution of taxable income issues associated with NUG trust fund proceeds. The PPUC is reviewing a January 2006 change in Met-Ed’s and Penelec’s NUG purchase power stranded cost accounting methodology. If the PPUC orders Met-Ed and Penelec to reverse the change in accounting methodology, this would result in a pre-tax loss of $10.3 million for Met-Ed.
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 all intervened in the case. 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 have deferred approximately $46 million and $12 million, respectively, representing transmission costs that were incurred from January 1, 2006 through June 30, 2006. On June 5, 2006, the OCA filed before the Commonwealth Court a petition for review of the PPUC’s approval of the deferral. On July 12, 2006, the Commonwealth Court granted the PPUC’s motion to quash the OCA’s appeal. The ratemaking treatment of the deferrals will be determined in the comprehensive rate filing proceeding discussed further below. 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 defer 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.
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 an agent for Met-Ed or Penelec in procuring the services under 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 CBP 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 of $37 million annually and an increase in distribution rates for Penelec of $20 million annually. The PPUC suspended the effective date (June 10, 2006) of these rate changes for seven months after the filing as permitted under Pennsylvania law. If the PPUC adopts the overall positions taken in the intervenors’ testimony as filed, this would have a material adverse effect on the financial statements of FirstEnergy, Met-Ed and Penelec. Hearings are scheduled for late August 2006 and a PPUC decision is expected early in the first quarter of 2007.
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 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. To the extent that an affiliate of Penn supplies a portion of the PLR load included in the RFP, authorization to make the affiliate sale must be obtained from the FERC. Hearings before the PPUC 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. On April 20, 2006, the PPUC approved the Recommended Decision with additional modifications to use an RFP process to obtain Penn's power supply requirements after 2006 through two separate solicitations. An initial solicitation was held for Penn in May 2006 with all tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results for the first solicitation. On July 18, 2006, the second PLR solicitation was held for Penn. The tranches for the Residential Group and Small Commercial Group were fully subscribed. However, supply was only acquired for three of the five tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved the submissions for the second bid. A residual solicitation is scheduled to be held on August 15, 2006 for the two remaining Large Commercial Group tranches. Acceptance of the winning bids is subject to approval by the PPUC. On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of April 28, 2006 and May 4, 2006, which together decided the issues associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the Commonwealth Court to review the PPUC’s decision to deny its recovery of certain PLR costs via a reconciliation mechanism and its decision to impose a geographic limitation on the sources of alternative energy credits. On June 7, 2006, the PaDEP filed a Petition for Review appealing the PPUC’s ruling on the method by which alternative energy credits may be acquired and traded. Penn is unable to predict the outcome of this appeal.
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 June 30, 2006, the accumulated deferred cost balance totaled approximately $638 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 June 8, 2006, the NJBPU approved JCP&L’s request to issue securitization bonds associated with BGS stranded cost deferrals. On August 4, 2006, JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, secured pricing on the issuance of $182 million of transition bonds with a weighted average interest rate of 5.5%. On December 2, 2005, JCP&L filed its 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 23, 2006, JCP&L filed updated data reflecting actual amounts through December 31, 2005 of $154 million of costs incurred since July 31, 2003. 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 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 last of the quarterly reliability reports was submitted on June 12, 2006. As of June 30, 2006, there were no performance penalties issued by the NJBPU. 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. On June 21, 2006, the NJBPU approved the continued use of a descending block auction for the Fixed Price Residential Class. A final decision as to the procurement method for the Commercial Industrial Energy Price Class is expected in October 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 DRA filed comments on February 28, 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 repeal of PUHCA pursuant to 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 on 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. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. Comments on the alternative proposal were submitted on June 15, 2006. JCP&L is unable to predict the outcome of this proceeding. 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. JCP&L was advised by the IRS on April 10, 2006 that the ruling was tentatively adverse. On April 28, 2006, the NJBPU directed JCP&L to withdraw its request for a private letter ruling on this issue, which had been previously filed with the IRS as ordered by the NJBPU. On May 11, 2006, after a JCP&L Motion for Reconsideration was denied by the NJBPU, JCP&L filed to withdraw the request for a private letter ruling. On July 19, 2006, the IRS acknowledged that the JCP&L ruling request was withdrawn.
FERC MATTERS
On November 1, 2004, ATSI requested authority fromfiled with the FERC a request to defer approximately $54 million of vegetation management costs ($17 million deferred as of June 30, 2005) estimated to be incurred from 2004 through 2007.2007 in connection with ATSI’s 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.the VMEP costs (approximately $33 million has been deferred as of June 30, 2006). On March 28, 2006, ATSI expects to file an application with FERC in the first quarter of 2006 for recovery of the deferred costs.
On December 30, 2004, the Ohio Companiesand MISO filed with the PUCO two applications relatedFERC a request to themodify ATSI’s Attachment O formula rate to include revenue requirements associated with recovery of transmission and ancillary service related costs. The first application seeks recovery of thesedeferred VMEP costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $30 million per year; however, the Ohio Companies anticipate that this amount will increase. The Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted thereafter each July 1. The Ohio Companies reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by the Ohio Companies, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. If the settlement stipulation is approved by the PUCO, the actual amounts to be recovered through the January 1, 2006 rider will be submitted to the PUCO on or before November 1, 2005.
The second application seeks 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 defer incremental transmission and ancillary service-related charges incurred as a participant in the MISO, but only for those costs incurred during the period December 30, 2004, through December 31, 2005. Deferral of all costs incurred prior to December 31, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period throughperiod. The requested effective date to begin recovery was June 1, 2006. Various parties filed comments responsive to the rider, beginning inMarch 28, 2006 is pending.submission. The OCC, OPAE andFERC conditionally approved the Ohio Companies eachfiling on May 22, 2006, subject to a compliance filing that ATSI made on June 13, 2006. A request for rehearing of the FERC’s May 22, 2006 Order was filed applications for rehearing. The Ohio Companies sought authority to defer the transmission and ancillary service related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs.by a party, which ATSI answered. On July 6, 2005,21, 2006, the PUCO deniedFERC issued an order stating that it needs more time to consider the Ohio Companies and OCC’s applications and, atmatter. In light of that order, there is no time period by which the request ofFERC must act on the Ohio Companies, struck as untimely OPAE’s application.pending rehearing request. On July 14, 2006, the FERC accepted ATSI’s June 13, 2006 compliance filing. The Ohio Companies andestimated annual revenues to ATSI from the OCC have sixty days from that date to file a notice of appeal with the Ohio Supreme Court. VMEP cost recovery is $12 million.
On January 12, 2005, Met-Ed24, 2006, ATSI and PenelecMISO filed a request with the PPUC for deferralFERC to correct ATSI’s Attachment O formula rate to reverse revenue credits associated with termination of transmission-related costs beginning Januaryrevenue streams from transitional rates stemming from FERC’s elimination of RTOR. 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, 2005, estimated to be approximately $8 million per month.
Various parties have intervened in each2008. On March 16, 2006, the FERC approved the revenue credit correction without suspension, effective April 1, 2006. One party sought rehearing of the cases above,FERC's order. The request for rehearing of this order was denied on June 27, 2006. The FERC accepted MISO’s and ATSI’s revised tariff sheets for filing on June 7, 2006. The estimated annual revenue impact of the Companies have not yet implemented deferral accounting for these costs.correction mechanism is approximately $40 million effective on June 1, 2006.
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 CEI andeliminating the cities of Cleveland and Painesville, Ohio. Under the FERC's original decision, CEI would have been responsible for a portion of new energy market charges imposed by MISO when its energy markets began 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, which became effecitve April 1, 2005. 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 citiesRTOR for transmission service between the MISO and MISO's abilityPJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to administersubmit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the contracts. Accordingly,SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be involved in the impactFERC hearings concerning the calculation and imposition of thisthe SECA charges. The hearing was held in May 2006. Initial briefs were submitted on June 9, 2006, and reply briefs were filed on June 27, 2006. The FERC has ordered the Presiding Judge to issue an initial decision cannot be determined at this time.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 referralrefund and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order.
Regulatory Assets
On March 20, 2006, a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The EUOC recognize, as regulatory assets, costs whichFERC issued an order approving this settlement on April 19, 2006. Hearings in the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate. The ALJ recommended an April 1, 2006 effective date for this change in rate design. If the FERC PUCO, PPUC and NJBPU have authorized for recovery from customersaccepts this recommendation, the transmission rate applicable to many load zones in future periods. Without the probability of such authorization, costs currently recorded as regulatory assetsPJM would increase. FirstEnergy believes that significant additional transmission revenues 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 - $274 million, CEI - $354 million, TE - $108 million, as of June 30, 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 June 30, 2005 for JCP&L, Met-Ed and Penelec are approximately $2.2 billion, $0.7 billion and $0.1 billion, respectively. Deferral of above-market costs from power supplied by NUGs to JCP&L are approximately $1.1 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 $0.1 billion, respectively. These costs are being recovered through CTC revenues.transmission zones within PJM. The regulatory asset for above-market NUG costs and the corresponding liability are adjusted to fair value at the end of each quarter. RecoveryCompanies, as part of the remaining regulatory transition costsResponsible Pricing Alliance, intend to submit a brief on exceptions within thirty days of the initial decision. Following submission of reply exceptions, the case is expected to continue underbe reviewed by the provisionsFERC with a decision anticipated in the fourth quarter of 2006.
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 various regulatory proceedingsOhio 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 CBP results in New Jerseya lower price for retail customers. A similar power sales agreement between FES and Pennsylvania.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 through two separate solicitations. An initial solicitation was held for Penn in May 2006 with all tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results for the first solicitation. On July 18, 2006, the second PLR solicitation was held for Penn. The tranches for the Residential Group and Small Commercial Group were fully subscribed. However, supply was only acquired for three of the five tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved the submission for the second bid. A residual solicitation is scheduled to be held on August 15, 2006 for the two remaining Large Commercial Group tranches. Acceptance of the winning bids is subject to approval by the PPUC. On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticized the Ohio CBP, 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. Under the procedural schedule approved in this case, FES expected an initial decision to be issued in late January 2007. However, on July 14, 2006, the Chief Judge granted the joint motion of FES and the Trial Staff to appoint a settlement judge in this proceeding. The procedural schedule has been suspended pending settlement discussions among the parties.
1512. - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
| SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"FSP FIN 46(R)-6 - “Determining the Variability to Be Considered in Applying FASB interpretation No. 46(R)”
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In May 2005,April 2006, the FASB issued SFAS 154 to changeFSP FIN 46(R)-6 that addresses how a reporting enterprise should determine the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. FirstEnergy and the Companies will adopt this Statement effective January 1, 2006.
FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
On March 30, 2005, the FASB issued FIN 47 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 isvariability to be recognizedconsidered in applying FASB interpretation No. 46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the first periodquarter of 2004, consolidating VIE’s when FirstEnergy or one of its subsidiaries is determined to be the VIE’s primary beneficiary. The variability that is considered in applying interpretation 46(R) affects the determination of (a) whether the entity is a VIE; (b) 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. Therefore, FirstEnergy will adopt this Interpretationinterests are variable interests in the fourth quarterentity; and (c) which party, if any, is the primary beneficiary of 2005. FirstEnergy and the Companies are currently evaluatingVIE. This FSP states that the effect this Interpretation will havevariability to be considered shall be based on their financial statements.an analysis of the design of the entity, involving two steps:
| Step 1: | SFAS 153, "ExchangesAnalyze the nature of Nonmonetary Assets - an amendment of APB Opinion No. 29"
the risks in the entity | | Step 2: | Determine the purpose(s) for which the entity was created and determine the variability the entity is designed to create and pass along to its interest holders. |
In December 2004,After determining the FASB issued SFAS 153 amending APB 29,variability to consider, the reporting enterprise can determine which was based on the principleinterests are designed to absorb that nonmonetary assets should be measured based on the fair value of the assets exchanged.variability. The guidance in APB 29 included certain exceptionsthis FSP is applied prospectively to all entities (including newly created entities) with which that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assetsenterprise first becomes involved 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 areall entities previously required to be applied prospectively. Asanalyzed under interpretation 46(R) when a result,reconsideration event has occurred after July 1, 2006. FirstEnergy will adopt this Statement effective January 1, 2006, and does not expect itthis Statement to have a material impact on its financial statements.
SFAS 123(R), "Share-Based Payment"FIN 48 - “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109.”
In December 2004,June 2006, the FASB issued SFAS 123(R),FIN 48 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes a revisionrecognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to SFAS 123, which requires expensing stock optionsbe taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation will be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit to recognize in the financial statements. Important to applying the new standardThis interpretation 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 companies with a fiscal year beginning January 1. Therefore, FirstEnergy will adopt this Statement effective January 1, 2006. 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"
|
In November 2004, the FASB issued SFAS 151 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 FirstEnergyfiscal years beginning January 1,after December 15, 2006. FirstEnergy is currently evaluating the impact of this Standard and 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 indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy continues 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"
|
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 nine 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 109, "Accounting for Income Taxes." FirstEnergy is currently evaluating this FSP and does not expect it to have a material impact on the Company's financial statements.Statement.
1613. - SEGMENT INFORMATION:INFORMATION
FirstEnergy has threetwo reportable segments: regulated services and power supply management services 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 EUOCsutility 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 June 30, 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 forsupplies all of the electric power needs of FirstEnergy’s generation operations. Itsend-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 customers primarily in Ohio, Pennsylvania, Maryland 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 taxes relatedancillary costs charged by PJM and MISO to those generating units.deliver energy to retail customers.
Segment reporting for interim periods in 20042005 was reclassifiedrevised to conform withto the current year business segment organization and operations that were reported in the 2004 Form 10-K, emphasizing FirstEnergy's regulated electric businesses and power supply management operations and the reclassification of discontinued operations (see Note 6)4). Changes in the current year operations reporting reflected in the revised 2005 segment reporting primarily includes the transfer of retail transmission revenues and PJM/MISO transmission revenues and expenses associated with serving electricity load previously included in the regulated services segment to the power supply management services segment. In addition, as a result of the 2005 Ohio tax legislation reducing the effective state income tax rate, the calculated composite income tax rates used in the two reportable segments’ results for 2005 and 2006 have been changed to 40% from the 41% previously reported in their 2005 segment results. The net amounts of the changes in the 2005 reportable segments' income taxes reclassifications have been correspondingly offset in the 2005 "Reconciling Adjustments." FSG is being disclosed as a reportingreportable segment due to theits subsidiaries qualifying as held for sale (see Note 6 for discussion of the divestiture of three 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 | | | | | | | | | | | | | Regulated | | Management | | Facilities | | | | Reconciling | | | | | | | Services | | Services | | Services | | Other | | Adjustments | | Consolidated | | | | | (In millions) | | Three Months Ended: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | June 30, 2005 | | | | | | | | | | | | | | | External revenues | | $ | 1,351 | | $ | 1,379 | | $ | 56 | | $ | 137 | | $ | 6 | | $ | 2,929 | | | Internal revenues | | | 80 | | | - | | | - | | | - | | | (80 | ) | | - | | | Total revenues | | | 1,431 | | | 1,379 | | | 56 | | | 137 | | | (74 | ) | | 2,929 | | | Depreciation and amortization | | | 322 | | | 7 | | | - | | | - | | | 6 | | | 335 | | | Net interest charges | | | 99 | | | 8 | | | 1 | | | 2 | | | 51 | | | 161 | | | Income taxes | | | 186 | | | 7 | | | 3 | | | 4 | | | 41 | | | 241 | | | Income before discontinued operations | | | 267 | | | 11 | | | (3 | ) | | 6 | | | (102 | ) | | 179 | | | Discontinued operations | | | - | | | - | | | - | | | (1 | ) | | - | | | (1 | ) | | Net income | | | 267 | | | 11 | | | (3 | ) | | 5 | | | (102 | ) | | 178 | | | Total assets | | | 28,454 | | | 1,601 | | | 78 | | | 512 | | | 566 | | | 31,211 | | | Total goodwill | | | 5,946 | | | 24 | | | - | | | 63 | | | - | | | 6,033 | | | Property additions | | | 158 | | | 66 | | | - | | | 2 | | | 7 | | | 233 | | | | | | | | | | | | | | | | | | | | | | | June 30, 2004 | | | | | | | | | | | | | | | | | | | | | External revenues | | $ | 1,278 | | $ | 1,550 | | $ | 50 | | $ | 119 | | $ | (5 | ) | $ | 2,992 | | | Internal revenues | | | 80 | | | - | | | - | | | - | | | (80 | ) | | - | | | Total revenues | | | 1,358 | | | 1,550 | | | 50 | | | 119 | | | (85 | ) | | 2,992 | | | Depreciation and amortization | | | 330 | | | 9 | | | - | | | - | | | 10 | | | 349 | | | Net interest charges | | | 113 | | | 10 | | | - | | | 1 | | | 56 | | | 180 | | | Income taxes | | | 171 | | | 26 | | | - | | | (22 | ) | | 2 | | | 177 | | | Income before discontinued operations | | | 234 | | | 37 | | | - | | | 36 | | | (105 | ) | | 202 | | | Discontinued operations | | | - | | | - | | | 1 | | | 1 | | | - | | | 2 | | | Net income | | | 234 | | | 37 | | | 1 | | | 37 | | | (105 | ) | | 204 | | | Total assets | | | 29,101 | | | 1,475 | | | 174 | | | 604 | | | 656 | | | 32,010 | | | Total goodwill | | | 5,965 | | | 24 | | | 37 | | | 75 | | | - | | | 6,101 | | | Property additions | | | 129 | | | 58 | | | 1 | | | 1 | | | 7 | | | 196 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Six Months Ended: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | June 30, 2005 | | | | | | | | | | | | | | | | | | | | | External revenues | | $ | 2,690 | | $ | 2,673 | | $ | 102 | | $ | 247 | | $ | 18 | | $ | 5,730 | | | Internal revenues | | | 158 | | | - | | | - | | | - | | | (158 | ) | | - | | | Total revenues | | | 2,848 | | | 2,673 | | | 102 | | | 247 | | | (140 | ) | | 5,730 | | | Depreciation and amortization | | | 698 | | | 17 | | | - | | | 1 | | | 13 | | | 729 | | | Net interest charges | | | 197 | | | 18 | | | 1 | | | 3 | | | 113 | | | 332 | | | Income taxes | | | 341 | | | (17 | ) | | 2 | | | 11 | | | 26 | | | 363 | | | Income before discontinued operations | | | 490 | | | (25 | ) | | (5 | ) | | 11 | | | (151 | ) | | 320 | | | Discontinued operations | | | - | | | - | | | 13 | | | 5 | | | - | | | 18 | | | Net income | | | 490 | | | (25 | ) | | 8 | | | 16 | | | (151 | ) | | 338 | | | Total assets | | | 28,454 | | | 1,601 | | | 78 | | | 512 | | | 566 | | | 31,211 | | | Total goodwill | | | 5,946 | | | 24 | | | - | | | 63 | | | - | | | 6,033 | | | Property additions | | | 299 | | | 147 | | | 1 | | | 4 | | | 11 | | | 462 | | | | | | | | | | | | | | | | | | | | | | | June 30, 2004 | | | | | | | | | | | | | | | | | | | | | External revenues | | $ | 2,568 | | $ | 3,072 | | $ | 95 | | $ | 234 | | $ | 6 | | $ | 5,975 | | | Internal revenues | | | 159 | | | - | | | - | | | - | | | (159 | ) | | - | | | Total revenues | | | 2,727 | | | 3,072 | | | 95 | | | 234 | | | (153 | ) | | 5,975 | | | Depreciation and amortization | | | 722 | | | 17 | | | 1 | | | - | | | 20 | | | 760 | | | Net interest charges | | | 219 | | | 21 | | | - | | | 2 | | | 109 | | | 351 | | | Income taxes | | | 316 | | | 25 | | | (1 | ) | | (18 | ) | | (30 | ) | | 292 | | | Income before discontinued operations | | | 446 | | | 36 | | | (2 | ) | | 41 | | | (147 | ) | | 374 | | | Discontinued operations | | | - | | | - | | | 2 | | | 2 | | | - | | | 4 | | | Net income | | | 446 | | | 36 | | | - | | | 43 | | | (147 | ) | | 378 | | | Total assets | | | 29,101 | | | 1,475 | | | 174 | | | 604 | | | 656 | | | 32,010 | | | Total goodwill | | | 5,965 | | | 24 | | | 37 | | | 75 | | | - | | | 6,101 | | | Property additions | | | 220 | | | 102 | | | 2 | | | - | | | 11 | | | 335 | | | | | | | | | | | | | | | | | | | | | | | | 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 are reflected as reductions | | | | | to expenses for internal management reporting purposes, the impact from the phase-out of the State of Ohio income tax and elimination of intersegment transactions. | | | | | | | | | | | | | | | | | | | | | | | | | | |
Segment Financial Information | | | | Power | | | | | | | | | | | | | | | Supply | | | | | | | | | | | | | Regulated | | Management | | Facilities | | | | Reconciling | | | | Three Months Ended | | Services | | Services | | Services | | Other | | Adjustments | | Consolidated | | | | (In millions) | | June 30, 2006 | | | | | | | | | | | | | | | External revenues | | $ | 1,045 | | $ | 1,678 | | $ | 58 | | $ | 16 | | $ | (11 | ) | $ | 2,786 | | | Internal revenues | | | - | | | - | | | - | | | - | | | - | | | - | | | Total revenues | | | 1,045 | | | 1,678 | | | 58 | | | 16 | | | (11 | ) | | 2,786 | | | Depreciation and amortization | | | 228 | | | (36 | ) | | - | | | 1 | | | 5 | | | 198 | | | Investment Income | | | 75 | | | 2 | | | - | | | 1 | | | (47 | ) | | 31 | | | Net interest charges | | | 96 | | | 54 | | | 1 | | | 1 | | | 21 | | | 173 | | | Income taxes | | | 155 | | | 90 | | | 1 | | | 2 | | | (31 | ) | | 217 | | | Net income | | | 229 | | | 135 | | | (11 | ) | | (4 | ) | | (45 | ) | | 304 | | | Total assets | | | 24,630 | | | 6,740 | | | 56 | | | 299 | | | 853 | | | 32,578 | | | Total goodwill | | | 5,916 | | | 24 | | | - | | | - | | | - | | | 5,940 | | | Property additions | | | 161 | | | 103 | | | - | | | 1 | | | 13 | | | 278 | | | | | | | | | | | | | | | | | | | | | | June 30, 2005 | | | | | | | | | | | | | | | | | | | | | External revenues | | $ | 1,226 | | $ | 1,416 | | $ | 59 | | $ | 135 | | $ | 7 | | $ | 2,843 | | | Internal revenues | | | 80 | | | - | | | - | | | - | | | (80 | ) | | - | | | Total revenues | | | 1,306 | | | 1,416 | | | 59 | | | 135 | | | (73 | ) | | 2,843 | | | Depreciation and amortization | | | 344 | | | (16 | ) | | - | | | - | | | 7 | | | 335 | | | Investment income | | | 47 | | | - | | | - | | | - | | | - | | | 47 | | | Net interest charges | | | 99 | | | 9 | | | - | | | 2 | | | 51 | | | 161 | | | Income taxes | | | 193 | | | (5 | ) | | 5 | | | 1 | | | 47 | | | 241 | | | Income before discontinued operations | | | 288 | | | (5 | ) | | (2 | ) | | 6 | | | (108 | ) | | 179 | | | Discontinued operations | | | - | | | - | | | - | | | (1 | ) | | - | | | (1 | ) | | Net income | | | 288 | | | (5 | ) | | (2 | ) | | 5 | | | (108 | ) | | 178 | | | Total assets | | | 28,454 | | | 1,601 | | | 78 | | | 512 | | | 566 | | | 31,211 | | | Total goodwill | | | 5,946 | | | 24 | | | - | | | 63 | | | - | | | 6,033 | | | Property additions | | | 158 | | | 66 | | | - | | | 2 | | | 7 | | | 233 | |
Six Months Ended | | | | | | | | | | | | | | | | | | | | | | | | | | | | | June 30, 2006 | | | | | | | | | | | | | | | External revenues | | $ | 2,128 | | $ | 3,297 | | $ | 104 | | $ | 136 | | $ | (34 | ) | $ | 5,631 | | | Internal revenues | | | - | | | - | | | - | | | - | | | - | | | - | | | Total revenues | | | 2,128 | | | 3,297 | | | 104 | | | 136 | | | (34 | ) | | 5,631 | | | Depreciation and amortization | | | 486 | | | (11 | ) | | - | | | 2 | | | 10 | | | 487 | | | Investment Income | | | 137 | | | 17 | | | - | | | 1 | | | (81 | ) | | 74 | | | Net interest charges | | | 189 | | | 103 | | | 1 | | | 2 | | | 38 | | | 333 | | | Income taxes | | | 299 | | | 117 | | | 1 | | | (5 | ) | | (61 | ) | | 351 | | | Net income | | | 440 | | | 175 | | | (12 | ) | | 11 | | | (89 | ) | | 525 | | | Total assets | | | 24,630 | | | 6,740 | | | 56 | | | 299 | | | 853 | | | 32,578 | | | Total goodwill | | | 5,916 | | | 24 | | | - | | | - | | | - | | | 5,940 | | | Property additions | | | 356 | | | 347 | | | - | | | 2 | | | 20 | | | 725 | | | | | | | | | | | | | | | | | | | | | | June 30, 2005 | | | | | | | | | | | | | | | | | | | | | External revenues | | $ | 2,442 | | $ | 2,793 | | $ | 102 | | $ | 247 | | $ | 9 | | $ | 5,593 | | | Internal revenues | | | 158 | | | - | | | - | | | - | | | (158 | ) | | - | | | Total revenues | | | 2,600 | | | 2,793 | | | 102 | | | 247 | | | (149 | ) | | 5,593 | | | Depreciation and amortization | | | 718 | | | (3 | ) | | - | | | 1 | | | 13 | | | 729 | | | Investment income | | | 88 | | | - | | | - | | | - | | | - | | | 88 | | | Net interest charges | | | 197 | | | 19 | | | - | | | 3 | | | 113 | | | 332 | | | Income taxes | | | 350 | | | (35 | ) | | 2 | | | 11 | | | 34 | | | 362 | | | Income before discontinued operations | | | 524 | | | (51 | ) | | (4 | ) | | 11 | | | (160 | ) | | 320 | | | Discontinued operations | | | - | | | - | | | 13 | | | 5 | | | - | | | 18 | | | Net income | | | 524 | | | (51 | ) | | 9 | | | 16 | | | (160 | ) | | 338 | | | Total assets | | | 28,454 | | | 1,601 | | | 78 | | | 512 | | | 566 | | | 31,211 | | | Total goodwill | | | 5,946 | | | 24 | | | - | | | 63 | | | - | | | 6,033 | | | Property additions | | | 299 | | | 147 | | | 1 | | | 4 | | | 11 | | | 462 | |
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 are reflected as reductions to expenses for internal management reporting purposes) and elimination of intersegment transactions.
1714. - FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS
On May 13, 2005, Penn, and on May 18, 2005, OE, CEI and TE,the Ohio Companies, entered into certain agreements described below (Agreements) implementing a series of intra-system generation asset transfers. When concluded,transfers that were completed in the fourth quarter of 2005. The asset transfers will resultresulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear fossil and hydroelectric plantsnon-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests that are being 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 are being undertaken in connection withwere 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. FENOC, a subsidiary of FirstEnergy, currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a master facility lease, leases the non-nuclear generation assets to be transferred and operates and maintains those assets. The transactions will essentially completecompleted the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO respectively, without impacting the operation of the plants. 15. - JCP&L RESTATEMENT
As contemplatedJCP&L's earnings for the three months and six months ended June 30, 2005 have been restated to reflect the results of a tax audit by the Agreements,State of New Jersey, in which JCP&L became aware that the Ohio CompaniesNew 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 Penn intend to transfer their respective interestsas a result, income taxes and interest expense were understated by $0.4 million and $0.6 million, respectively, in the nuclear generation assets to NGC through,second quarter of 2005 and understated by $0.9 million and $1.2 million, respectively, in the casefirst six months of OE2005. The effects of these adjustments on JCP&L's Consolidated Statements of Income for the three months and Penn, a spin-off by waysix months ended June 30, 2005 are as follows:
| | | Three Months | | Six Months | | | | As Previously | | | As | | As Previously | | As | | | | Reported | | | Restated | | Reported | | Restated | | | | (In millions) | | Operating Revenues | $ | 595.3 | | $ | 595.3 | | $ | 1,124.4 | | $ | 1,124.4 | | Operating Expenses and | | | | | | | | | | | | | Taxes | | 521.2 | | | 521.6 | | | 1,015.9 | | | 1,016.8 | | Operating Income | | 74.1 | | | 73.7 | | | 108.5 | | | 107.6 | | Other Income | | 0.3 | | | 0.3 | | | 0.3 | | | 0.3 | | Net Interest Charges | | 19.1 | | | 19.7 | | | 39.0 | | | 40.2 | | Net Income | $ | 55.3 | | $ | 54.3 | | $ | 69.8 | | $ | 67.7 | | Earnings Applicable | | | | | | | | | | | | | to Common Stock | $ | 55.2 | | $ | 54.2 | | $ | 69.6 | | $ | 67.5 |
These adjustments were not material to FirstEnergy's consolidated financial statements, nor JCP&L's Consolidated Balance Sheets or Consolidated Statements of dividend and, in the case of CEI and TE, a sale at net book value. FGCO intends to exercise a purchase option under the Master Lease to acquire the non-nuclear generation assets to be transferred by the Ohio Companies and Penn at the values approved in the Ohio Transition Case.Cash Flows.
Consummation of the transactions contemplated by each of the Agreements is subject to receipt of all necessary regulatory authorizations and other consents and approvals. FirstEnergy currently expects to complete the various asset transfers in the second half of 2005.16. - SUBSEQUENT EVENTS
Pennsylvania Law Change
On July 12, 2006, the Governor of Pennsylvania signed House Bill 859, which increases the net operating loss deduction allowed for the corporate net income tax from $2 million to $3 million, or the greater of 12.5% of taxable income. As a result, FirstEnergy expects to recognize a net operating loss benefit of $2.2 million (net of federal tax benefit) in the third quarter of 2006.
FIRSTENERGY CORP. | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In thousands, except per share amounts) | | REVENUES: | | | | | | | | | | | Electric utilities | | $ | 2,329,795 | | $ | 2,170,570 | | $ | 4,638,311 | | $ | 4,347,603 | | | Unregulated businesses (Note 2) | | | 599,483 | | | 821,592 | | | 1,091,686 | | | 1,627,462 | | | Total revenues | | | 2,929,278 | | | 2,992,162 | | | 5,729,997 | | | 5,975,065 | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | Fuel and purchased power (Note 2) | | | 932,596 | | | 1,095,135 | | | 1,827,928 | | | 2,229,461 | | | Other operating expenses | | | 912,592 | | | 832,398 | | | 1,805,587 | | | 1,631,742 | | | Provision for depreciation | | | 149,025 | | | 146,155 | | | 291,657 | | | 291,965 | | | Amortization of regulatory assets | | | 306,572 | | | 270,986 | | | 617,413 | | | 581,188 | | | Deferral of new regulatory assets | | | (120,162 | ) | | (68,315 | ) | | (179,669 | ) | | (112,720 | ) | | General taxes | | | 167,865 | | | 157,732 | | | 353,044 | | | 336,722 | | | Total expenses | | | 2,348,488 | | | 2,434,091 | | | 4,715,960 | | | 4,958,358 | | | | | | | | | | | | | | | | | INCOME BEFORE INTEREST AND INCOME TAXES | | | 580,790 | | | 558,071 | | | 1,014,037 | | | 1,016,707 | | | | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | | | | Interest expense | | | 161,714 | | | 179,542 | | | 326,358 | | | 352,048 | | | Capitalized interest | | | (4,697 | ) | | (5,280 | ) | | (4,952 | ) | | (11,750 | ) | | Subsidiaries’ preferred stock dividends | | | 3,733 | | | 5,389 | | | 10,286 | | | 10,670 | | | Net interest charges | | | 160,750 | | | 179,651 | | | 331,692 | | | 350,968 | | | | | | | | | | | | | | | | | INCOME TAXES | | | 241,275 | | | 176,560 | | | 362,550 | | | 291,530 | | | | | | | | | | | | | | | | | INCOME BEFORE DISCONTINUED OPERATIONS | | | 178,765 | | | 201,860 | | | 319,795 | | | 374,209 | | | | | | | | | | | | | | | | | | Discontinued operations (net of income taxes (benefit) of | | | | | | | | | | | | | | | $(1,282,000) and $993,000 in the three months ended | | | | | | | | | | | | | | | June 30, and $(9,051,000) and $2,137,000 in the six | | | | | | | | | | | | | | | months ended June 30, of 2005 and 2004, respectively) | | | | | | | | | | | | | | | (Note 6) | | | (773 | ) | | 2,185 | | | 17,923 | | | 3,835 | | | | | | | | | | | | | | | | | NET INCOME | | $ | 177,992 | | $ | 204,045 | | $ | 337,718 | | $ | 378,044 | | | | | | | | | | | | | | | | | BASIC EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | | | | | | | Earnings before discontinued operations | | $ | 0.54 | | $ | 0.61 | | $ | 0.98 | | $ | 1.15 | | | Discontinued operations (Note 6) | | | - | | | 0.01 | | | 0.05 | | | 0.01 | | | Net earnings per basic share | | $ | 0.54 | | $ | 0.62 | | $ | 1.03 | | $ | 1.16 | | | | | | | | | | | | | | | | | WEIGHTED AVERAGE NUMBER OF BASIC SHARES | | | | | | | | | | | | | | OUTSTANDING | | | 328,063 | | | 327,284 | | | 327,986 | | | 327,171 | | | | | | | | | | | | | | | | | DILUTED EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | | | | | | | Earnings before discontinued operations | | $ | 0.54 | | $ | 0.61 | | $ | 0.97 | | $ | 1.14 | | | Discontinued operations (Note 6) | | | - | | | 0.01 | | | 0.05 | | | 0.01 | | | Net earnings per diluted share | | $ | 0.54 | | $ | 0.62 | | $ | 1.02 | | $ | 1.15 | | | | | | | | | | | | | | | | | WEIGHTED AVERAGE NUMBER OF DILUTED SHARES | | | | | | | | | | | | | | OUTSTANDING | | | 329,879 | | | 329,103 | | | 329,679 | | | 329,061 | | | | | | | | | | | | | | | | | DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | | $ | 0.4125 | | $ | 0.375 | | $ | 0.825 | | $ | 0.75 | | | | | | | | | | | | | | | | | | 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 | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In thousands) | | | | | | | | | | | | | NET INCOME | | $ | 177,992 | | $ | 204,045 | | $ | 337,718 | | $ | 378,044 | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE (LOSS) INCOME: | | | | | | | | | | | | | | | Unrealized gain (loss) on derivative hedges | | | (6,023 | ) | | 19,244 | | | 1,300 | | | 20,609 | | | Unrealized loss on available for sale securities | | | (16,137 | ) | | (19,122 | ) | | (24,123 | ) | | (2,193 | ) | | Other comprehensive (loss) income | | | (22,160 | ) | | 122 | | | (22,823 | ) | | 18,416 | | | Income tax expense (benefit) related to other | | | | | | | | | | | | | | | comprehensive income | | | 5,778 | | | (314 | ) | | 5,907 | | | (9,785 | ) | | Other comprehensive (loss) income, net of tax | | | (16,382 | ) | | (192 | ) | | (16,916 | ) | | 8,631 | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME | | $ | 161,610 | | $ | 203,853 | | $ | 320,802 | | $ | 386,675 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these | | statements. | | | | | | | | | | | | | |
New Jersey Law Change FIRSTENERGY CORP. | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | June 30, | | December 31, | | | | | 2005 | | 2004 | | | | | (In thousands) | | ASSETS | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 49,748 | | $ | 52,941 | | | Receivables - | | | | | | | | | Customers (less accumulated provisions of $35,174,000 and | | | | | | | | | $34,476,000, respectively, for uncollectible accounts) | | | 1,281,688 | | | 979,242 | | | Other (less accumulated provisions of $27,276,000 and | | | | | | | | | $26,070,000, respectively, for uncollectible accounts) | | | 162,864 | | | 377,195 | | | Materials and supplies, at average cost - | | | | | | | | | Owned | | | 393,999 | | | 363,547 | | | Under consignment | | | 114,179 | | | 94,226 | | | Prepayments and other | | | 301,557 | | | 145,196 | | | | | | 2,304,035 | | | 2,012,347 | | PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | In service | | | 22,654,302 | | | 22,213,218 | | | Less - Accumulated provision for depreciation | | | 9,576,245 | | | 9,413,730 | | | | | | 13,078,057 | | | 12,799,488 | | | Construction work in progress | | | 574,178 | | | 678,868 | | | | | | 13,652,235 | | | 13,478,356 | | INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 1,635,315 | | | 1,582,588 | | | Investments in lease obligation bonds | | | 905,754 | | | 951,352 | | | Other | | | 772,999 | | | 740,026 | | | | | | 3,314,068 | | | 3,273,966 | | DEFERRED CHARGES: | | | | | | | | | Regulatory assets | | | 5,178,218 | | | 5,532,087 | | | Goodwill | | | 6,032,539 | | | 6,050,277 | | | Other | | | 730,148 | | | 720,911 | | | | | | 11,940,905 | | | 12,303,275 | | | | | $ | 31,211,243 | | $ | 31,067,944 | | LIABILITIES AND CAPITALIZATION | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 943,740 | | $ | 940,944 | | | Short-term borrowings | | | 554,824 | | | 170,489 | | | Accounts payable | | | 696,310 | | | 610,589 | | | Accrued taxes | | | 684,259 | | | 657,219 | | | Other | | | 874,839 | | | 929,194 | | | | | | 3,753,972 | | | 3,308,435 | | CAPITALIZATION: | | | | | | | | | Common stockholders’ equity - | | | | | | | | | Common stock, $0.10 par value, authorized 375,000,000 shares - | | | | | | | | | 329,836,276 shares outstanding | | | 32,984 | | | 32,984 | | | Other paid-in capital | | | 7,047,469 | | | 7,055,676 | | | Accumulated other comprehensive loss | | | (330,028 | ) | | (313,112 | ) | | Retained earnings | | | 1,924,097 | | | 1,856,863 | | | Unallocated employee stock ownership plan common stock - | | | | | | | | | 1,830,883 and 2,032,800 shares, respectively | | | (34,126 | ) | | (43,117 | ) | | Total common stockholders' equity | | | 8,640,396 | | | 8,589,294 | | | Preferred stock of consolidated subsidiaries | | | 213,719 | | | 335,123 | | | Long-term debt and other long-term obligations | | | 9,568,954 | | | 10,013,349 | | | | | | 18,423,069 | | | 18,937,766 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 2,411,166 | | | 2,324,097 | | | Asset retirement obligations | | | 1,112,940 | | | 1,077,557 | | | Power purchase contract loss liability | | | 1,856,482 | | | 2,001,006 | | | Retirement benefits | | | 1,287,345 | | | 1,238,973 | | | Lease market valuation liability | | | 893,800 | | | 936,200 | | | Other | | | 1,472,469 | | | 1,243,910 | | | | | | 9,034,202 | | | 8,821,743 | | | COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13) | | | | | | | | | | | $ | 31,211,243 | | $ | 31,067,944 | | | | | | | | | | | | 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 | | Six Months Ended | | | | | June 30, | | June 30, | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In thousands) | | | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | Net income | | $ | 177,992 | | $ | 204,045 | | $ | 337,718 | | $ | 378,044 | | | Adjustments to reconcile net income to net cash from | | | | | | | | | | | | | | | operating activities - | | | | | | | | | | | | | | | Provision for depreciation | | | 149,025 | | | 146,155 | | | 291,657 | | | 291,965 | | | Amortization of regulatory assets | | | 306,572 | | | 270,986 | | | 617,413 | | | 581,188 | | | Deferral of new regulatory assets | | | (120,162 | ) | | (68,315 | ) | | (179,669 | ) | | (112,720 | ) | | Nuclear fuel and lease amortization | | | 18,930 | | | 23,132 | | | 37,578 | | | 45,006 | | | Amortization of electric service obligation | | | (10,054 | ) | | (4,818 | ) | | (15,505 | ) | | (9,541 | ) | | Deferred purchased power and other costs | | | (82,990 | ) | | (60,974 | ) | | (192,223 | ) | | (144,881 | ) | | Deferred income taxes and investment tax credits, net | | | 76,041 | | | (100,056 | ) | | 61,885 | | | (94,133 | ) | | Deferred rents and lease market valuation liability | | | (65,446 | ) | | (64,287 | ) | | (101,109 | ) | | (80,584 | ) | | Accrued retirement benefit obligations | | | 32,269 | | | 39,864 | | | 48,372 | | | 64,500 | | | Accrued compensation, net | | | 4,447 | | | 17,935 | | | (37,275 | ) | | 22,322 | | | Commodity derivative transactions, net | | | 13,921 | | | (23,992 | ) | | 14,108 | | | (54,779 | ) | | Loss (income) from discontinued operations (Note 6) | | | 773 | | | (2,185 | ) | | (17,923 | ) | | (3,835 | ) | | Decrease (increase) in operating assets - | | | | | | | | | | | | | | | Receivables | | | (225,972 | ) | | (101,304 | ) | | (135,309 | ) | | 171,442 | | | Materials and supplies | | | (59,309 | ) | | (20,617 | ) | | (51,852 | ) | | 963 | | | Prepayments and other current assets | | | (53,095 | ) | | (42,563 | ) | | (159,217 | ) | | (89,594 | ) | | Increase (decrease) in operating liabilities - | | | | | | | | | | | | | | | Accounts payable | | | 42,612 | | | 68,376 | | | 104,031 | | | (108,642 | ) | | Accrued taxes | | | (1,557 | ) | | 113,874 | | | 39,155 | | | 144,659 | | | Accrued interest | | | (112,388 | ) | | (93,341 | ) | | (3,787 | ) | | (7,063 | ) | | Prepayment for electric service - education programs | | | 241,685 | | | - | | | 241,685 | | | - | | | Other | | | 29,032 | | | 29,645 | | | 31,383 | | | (14,906 | ) | | Net cash provided from operating activities | | | 362,326 | | | 331,560 | | | 931,116 | | | 979,411 | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | New Financing - | | | | | | | | | | | | | | | Long-term debt | | | 245,350 | | | 303,162 | | | 245,350 | | | 884,720 | | | Short-term borrowings, net | | | 245,803 | | | - | | | 385,614 | | | - | | | Redemptions and Repayments - | | | | | | | | | | | | | | | Preferred stock | | | (41,750 | ) | | - | | | (139,650 | ) | | - | | | Long-term debt | | | (452,860 | ) | | (721,023 | ) | | (688,748 | ) | | (989,943 | ) | | Short-term borrowings, net | | | - | | | (59,563 | ) | | - | | | (447,104 | ) | | Net controlled disbursement activity | | | 29,461 | | | 25,385 | | | (476 | ) | | (17,271 | ) | | Common stock dividend payments | | | (135,178 | ) | | (121,321 | ) | | (270,484 | ) | | (243,786 | ) | | Net cash used for financing activities | | | (109,174 | ) | | (573,360 | ) | | (468,394 | ) | | (813,384 | ) | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | Property additions | | | (232,791 | ) | | (196,094 | ) | | (461,675 | ) | | (334,500 | ) | | Proceeds from asset sales | | | 7,483 | | | 200,008 | | | 61,207 | | | 211,447 | | | Nonutility generation trust contributions | | | - | | | - | | | - | | | (50,614 | ) | | Contributions to nuclear decommissioning trusts | | | (25,372 | ) | | (25,372 | ) | | (50,742 | ) | | (50,742 | ) | | Cash investments | | | 8,217 | | | 6,738 | | | 35,121 | | | 26,956 | | | Other | | | (42,132 | ) | | 75,789 | | | (49,826 | ) | | 16,989 | | | Net cash provided from (used for) investing activities | | | (284,595 | ) | | 61,069 | | | (465,915 | ) | | (180,464 | ) | | | | | | | | | | | | | | | | | Net decrease in cash and cash equivalents | | | (31,443 | ) | | (180,731 | ) | | (3,193 | ) | | (14,437 | ) | | Cash and cash equivalents at beginning of period | | | 81,191 | | | 280,269 | | | 52,941 | | | 113,975 | | | Cash and cash equivalents at end of period | | $ | 49,748 | | $ | 99,538 | | $ | 49,748 | | $ | 99,538 | | | | | | | | | | | | | | | | | | 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 INCOME | | (Unaudited) | | | | | | | | | | | | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2006 | | 2005 | | 2006 | | 2005 | | | | (In millions, except per share amounts) | | REVENUES: | | | | | | | | | | | Electric utilities | | $ | 2,341 | | $ | 2,283 | | $ | 4,681 | | $ | 4,550 | | | Unregulated businesses | | | 445 | | | 560 | | | 950 | | | 1,043 | | | Total revenues | | | 2,786 | | | 2,843 | | | 5,631 | | | 5,593 | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | Fuel and purchased power | | | 992 | | | 933 | | | 1,990 | | | 1,828 | | | Other operating expenses | | | 760 | | | 873 | | | 1,653 | | | 1,757 | | | Provision for depreciation | | | 144 | | | 149 | | | 292 | | | 292 | | | Amortization of regulatory assets | | | 199 | | | 306 | | | 421 | | | 617 | | | Deferral of new regulatory assets | | | (145 | ) | | (120 | ) | | (226 | ) | | (180 | ) | | General taxes | | | 173 | | | 168 | | | 366 | | | 353 | | | Total expenses | | | 2,123 | | | 2,309 | | | 4,496 | | | 4,667 | | | | | | | | | | | | | | | | OPERATING INCOME | | | 663 | | | 534 | | | 1,135 | | | 926 | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | Investment income | | | 31 | | | 47 | | | 74 | | | 88 | | | Interest expense | | | (178 | ) | | (162 | ) | | (343 | ) | | (326 | ) | | Capitalized interest | | | 7 | | | 5 | | | 14 | | | 4 | | | Subsidiaries’ preferred stock dividends | | | (2 | ) | | (4 | ) | | (4 | ) | | (10 | ) | | Net interest charges | | | (142 | ) | | (114 | ) | | (259 | ) | | (244 | ) | | | | | | | | | | | | | | | INCOME TAXES | | | 217 | | | 241 | | | 351 | | | 362 | | | | | | | | | | | | | | | | INCOME BEFORE DISCONTINUED OPERATIONS | | | 304 | | | 179 | | | 525 | | | 320 | | | | | | | | | | | | | | | | | Discontinued operations (net of income tax benefits of | | | | | | | | | | | | | | | $1 million and $9 million in the three months and | | | | | | | | | | | | | | | six months ended June 30, 2005, respectively) (Note 4) | | | - | | | (1 | ) | | - | | | 18 | | | | | | | | | | | | | | | | NET INCOME | | $ | 304 | | $ | 178 | | $ | 525 | | $ | 338 | | | | | | | | | | | | | | | | BASIC EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | | | | | | | Earnings before discontinued operations (Note 2) | | $ | 0.92 | | $ | 0.54 | | $ | 1.59 | | $ | 0.98 | | | Discontinued operations (Note 4) | | | - | | | - | | | - | | | 0.05 | | | Net earnings per basic share | | $ | 0.92 | | $ | 0.54 | | $ | 1.59 | | $ | 1.03 | | | | | | | | | | | | | | | | WEIGHTED AVERAGE NUMBER OF BASIC SHARES | | | | | | | | | | | | | | OUTSTANDING | | | 328 | | | 328 | | | 328 | | | 328 | | | | | | | | | | | | | | | | DILUTED EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | | | | | | | Earnings before discontinued operations (Note 2) | | $ | 0.91 | | $ | 0.54 | | $ | 1.58 | | $ | 0.97 | | | Discontinued operations (Note 4) | | | - | | | - | | | - | | | 0.05 | | | Net earnings per diluted share | | $ | 0.91 | | $ | 0.54 | | $ | 1.58 | | $ | 1.02 | | | | | | | | | | | | | | | | WEIGHTED AVERAGE NUMBER OF DILUTED SHARES | | | | | | | | | | | | | | OUTSTANDING | | | 330 | | | 330 | | | 330 | | | 330 | | | | | | | | | | | | | | | | DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | | $ | 0.45 | | $ | 0.4125 | | $ | 0.90 | | $ | 0.825 | | | | | | | | | | | | | | | | | 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 | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2006 | | 2005 | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | | | NET INCOME | | $ | 304 | | $ | 178 | | $ | 525 | | $ | 338 | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | Unrealized gain (loss) on derivative hedges | | | 36 | | | (6 | ) | | 73 | | | 1 | | | Unrealized gain (loss) on available for sale securities | | | (24 | ) | | (16 | ) | | 13 | | | (24 | ) | | Other comprehensive income (loss) | | | 12 | | | (22 | ) | | 86 | | | (23 | ) | | Income tax expense (benefit) related to other | | | | | | | | | | | | | | | comprehensive income | | | 4 | | | (6 | ) | | 31 | | | (6 | ) | | Other comprehensive income (loss), net of tax | | | 8 | | | (16 | ) | | 55 | | | (17 | ) | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME | | $ | 312 | | $ | 162 | | $ | 580 | | $ | 321 | | | | | | | | | | | | | | | | | 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) | | | | | | | June 30, | | December 31, | | | | | | | 2006 | | 2005 | | | | | | | (In millions) | ASSETS | | | | | | | | | | | | | | | | | CURRENT ASSETS: | | | | | | | | Cash and cash equivalents | $ | 583 | | $ | 64 | | | Receivables - | | | | | | | | | Customers (less accumulated provisions of $36 million and | | | | | | | | | | $38 million, respectively, for uncollectible accounts) | | 1,173 | | | 1,293 | | | | Other (less accumulated provisions of $27 million | | | | | | | | | | for uncollectible accounts in both periods) | | 173 | | | 205 | | | Materials and supplies, at average cost | | 629 | | | 518 | | | Prepayments and other | | 254 | | | 237 | | | | | | | | 2,812 | | | 2,317 | PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | In service | | 23,661 | | | 22,893 | | | Less - Accumulated provision for depreciation | | 9,883 | | | 9,792 | | | | | | | | 13,778 | | | 13,101 | | | Construction work in progress | | 642 | | | 897 | | | | | | | | 14,420 | | | 13,998 | INVESTMENTS: | | | | | | | | Nuclear plant decommissioning trusts | | 1,796 | | | 1,752 | | | Investments in lease obligation bonds | | 830 | | | 890 | | | Other | | | 745 | | | 709 | | | | | | | | 3,371 | | | 3,351 | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | Goodwill | | 5,940 | | | 6,010 | | | Regulatory assets | | 4,396 | | | 4,486 | | | Prepaid pension costs | | 1,013 | | | 1,023 | | | Other | | | 626 | | | 656 | | | | | | | 11,975 | | | 12,175 | | | | | | | $ | 32,578 | | $ | 31,841 | LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | Currently payable long-term debt | $ | 2,004 | | $ | 2,043 | | | Short-term borrowings | | 1,101 | | | 731 | | | Accounts payable | | 682 | | | 727 | | | Accrued taxes | | 750 | | | 800 | | | Other | | | 852 | | | 1,152 | | | | | | | | 5,389 | | | 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 | | 7,052 | | | 7,043 | | | | Accumulated other comprehensive income (loss) | | 35 | | | (20) | | | | Retained earnings | | 2,385 | | | 2,159 | | | | Unallocated employee stock ownership plan common stock - | | | | | | | | | | 960,651 and 1,444,796 shares, respectively | | (17) | | | (27) | | | | | | Total common stockholders' equity | | 9,488 | | | 9,188 | | | Preferred stock of consolidated subsidiaries | | 154 | | | 184 | | | Long-term debt and other long-term obligations | | 8,729 | | | 8,155 | | | | | | | | 18,371 | | | 17,527 | NONCURRENT LIABILITIES: | | | | | | | | Accumulated deferred income taxes | | 2,792 | | | 2,726 | | | Asset retirement obligations | | 1,160 | | | 1,126 | | | Power purchase contract loss liability | | 1,123 | | | 1,226 | | | Retirement benefits | | 1,355 | | | 1,316 | | | Lease market valuation liability | | 809 | | | 851 | | | Other | | | 1,579 | | | 1,616 | | | | | | | | 8,818 | | | 8,861 | COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10) | | | | | | | | | | | | $ | 32,578 | | $ | 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) | | | | | | | | | | Six Months Ended | | | | June 30, | | | | 2006 | | 2005 | | | | (In millions) | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | Net income | $ | 525 | | $ | 338 | | | Adjustments to reconcile net income to net cash from operating activities - | | | | | | | | Provision for depreciation | | 292 | | | 292 | | | Amortization of regulatory assets | | 421 | | | 617 | | | Deferral of new regulatory assets | | (226 | ) | | (180 | ) | | Nuclear fuel and lease amortization | | 30 | | | 38 | | | Deferred purchased power and other costs | | (239 | ) | | (210 | ) | | Deferred income taxes and investment tax credits, net | | 32 | | | 62 | | | Deferred rents and lease market valuation liability | | (105 | ) | | (101 | ) | | Accrued compensation and retirement benefits | | 33 | | | 11 | | | Commodity derivative transactions, net | | 25 | | | (6 | ) | | Income from discontinued operations | | - | | | (18 | ) | | Cash collateral | | (55 | ) | | 22 | | | Decrease (increase) in operating assets - | | | | | | | | Receivables | | 83 | | | (135 | ) | | Materials and supplies | | (71 | ) | | (52 | ) | | Prepayments and other current assets | | (81 | ) | | (159 | ) | | Increase (decrease) in operating liabilities - | | | | | | | | Accounts payable | | (40 | ) | | 104 | | | Accrued taxes | | (45 | ) | | 39 | | | Accrued interest | | - | | | (4 | ) | | Electric service prepayment programs | | (29 | ) | | 226 | | | Other | | 1 | | | 37 | | | Net cash provided from operating activities | | 551 | | | 921 | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | New Financing - | | | | | | | | Long-term debt | | 1,053 | | | 245 | | | Short-term borrowings, net | | 371 | | | 386 | | | Redemptions and Repayments - | | | | | | | | Preferred stock | | (30 | ) | | (140 | ) | | Long-term debt | | (487 | ) | | (689 | ) | | Net controlled disbursement activity | | 5 | | | - | | | Common stock dividend payments | | (296 | ) | | (270 | ) | | Net cash provided from (used for) financing activities | | 616 | | | (468 | ) | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | Property additions | | (725 | ) | | (462 | ) | | Proceeds from asset sales | | 59 | | | 61 | | | Proceeds from nuclear decommissioning trust fund sales | | 925 | | | 608 | | | Investments in nuclear decommissioning trust funds | | (932 | ) | | (659 | ) | | Cash investments | | 40 | | | 35 | | | Other | | (15 | ) | | (39 | ) | | Net cash used for investing activities | | (648 | ) | | (456 | ) | | | | | | | | | | Net increase (decrease) in cash and cash equivalents | | 519 | | | (3 | ) | | Cash and cash equivalents at beginning of period | | 64 | | | 53 | | | Cash and cash equivalents at end of period | $ | 583 | | $ | 50 | | | | | | | | | | | 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 June 30, 2005,2006, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2006 and 2005 and 2004.the consolidated statement of cash flows for the six-month period ended June 30, 2006 and 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 have 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[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)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 July 29, 2005August 4, 2006
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
EXECUTIVE SUMMARY
Net income in the second quarter of 20052006 was $304 million, or basic earnings of $0.92 per share of common stock ($0.91 diluted), compared with net income of $178 million, or basic and diluted earnings of $0.54 per share of common stock compared to net income of $204 million, or basic and diluted earnings of $0.62 per share of common stock forin the second quarter of 2004. Net income2005. FirstEnergy’s earnings increase was driven primarily by increased electric sales revenues, reduced nuclear operating expenses, cost deferrals authorized by the PUCO and PPUC, and reduced transition cost amortization for the Ohio Companies. Earnings in the second quarter and the first six months of 2005 was $338 million, or basic earnings of $1.03were reduced by $0.22 per share of common stock ($1.02 diluted) compareddue to $378additional income tax expense of $71 million from the enactment of tax legislation in Ohio. Net income in the second quarter and the first six months of 2004, or basic2006 reflected net after-tax charges associated with the sale and impairment of non-core assets of $9 million (or $0.03 per share) and $11 million (or $0.03 per share), respectively. The following Non-GAAP Reconciliation displays the unusual items resulting in the difference between GAAP and non-GAAP earnings.
Reconciliation of non-GAAP to GAAP | | 2006 | | 2005 | | | | | After-tax | | Basic | | After-tax | | Basic | | | | | Amount | | Earnings | | Amount | | Earnings | | Three Months Ended June 30, | | (Millions) | | Per Share | | (Millions) | | Per Share | | | Earnings Before Unusual Items (Non-GAAP) | | $ | 313 | | $ | 0.95 | | $ | 233 | | $ | 0.71 | | | Unusual Items: | | | | | | | | | | | | | | | Non-core asset sales/impairments | | | (9 | ) | | (0.03 | ) | | - | | | - | | | New regulatory assets - JCP&L rate settlement | | | - | | | - | | | 16 | | | 0.05 | | | Ohio tax write-off | | | - | | | - | | | (71 | ) | | (0.22 | ) | | Net Income (GAAP) | | $ | 304 | | $ | 0.92 | | $ | 178 | | $ | 0.54 | | | | | | | | | | | | | | | | | Six Months Ended June 30, | | | | | | | | | | | | | | | Earnings Before Unusual Items (Non-GAAP) | | $ | 536 | | $ | 1.62 | | $ | 388 | | $ | 1.18 | | | Unusual Items: | | | | | | | | | | | | | | | Non-core asset sales/impairments | | | (11 | ) | | (0.03 | ) | | 22 | | | 0.07 | | | Sammis plant New Source Review settlement | | | - | | | - | | | (14 | ) | | (0.04 | ) | | Davis-Besse NRC fine | | | - | | | - | | | (3 | ) | | (0.01 | ) | | New regulatory assets - JCP&L rate settlement | | | - | | | - | | | 16 | | | 0.05 | | | Ohio tax write-off | | | - | | | - | | | (71 | ) | | (0.22 | ) | | Net Income (GAAP) | | $ | 525 | | $ | 1.59 | | $ | 338 | | $ | 1.03 | | | | | | | | | | | | | | | | |
The Non-GAAP measure above, earnings before unusual items, is not calculated in accordance with GAAP because it excludes the impact of "unusual items." Unusual items reflect the impact on earnings of $1.16 per shareevents that are not routine or for which FirstEnergy believes the financial impact will disappear or become immaterial within a near-term finite period. By removing the earnings effect of common stock ($1.15 diluted).such issues that have been resolved or are expected to be resolved over the near term, management and investors can better measure FirstEnergy’s business and earnings potential. In particular, the non-core asset sales item refers to a finite set of energy-related assets that had been previously disclosed as held for sale, a substantial portion of which has already been sold. Similarly, the NRC fine in 2005 and further litigation settlements similar to the class action settlements in 2005 are not reasonably expected over the near term. Furthermore, FirstEnergy believes presenting normalized earnings calculated in this manner provides useful information to investors in evaluating the ongoing results of FirstEnergy’s businesses over the longer term and assists investors in comparing FirstEnergy’s operating performance to the operating performance of others in the energy sector.
DuringTotal electric generation sales were up by 3.9% over last year’s second quarter. For the six months ended June 30, 2006, electric generation sales rose 3.0% compared to the same period last year. The increase for both periods was primarily due to the return of customers to the Ohio Companies from third-party suppliers that exited the Ohio marketplace. Electric distribution deliveries were down 1.8% and 2.2% for the quarter and year-to-date periods ending June 30, reflecting milder weather conditions in 2006.
FirstEnergy's generating fleet produced a second quarter record 20.3 billion KWH during the second quarter of 2005, JCP&L settled two rate cases, resulting2006 compared to 19.1 billion KWH in a one-time net gain of $0.05 per share of common stock for the quarter. Also, due to a tax law change in the State of Ohio, FirstEnergy wrote-off $72 million of net deferred tax benefits that are not expected to be realized during a five-year phase-out period for Ohio income taxes. This write-off reduced second-quarter earnings per share by $0.22.
During the second quarter of 2005, both2005. FirstEnergy's non-nuclear fleet produced a record 13.4 billion KWH, while its nuclear facilities produced 6.9 billion KWH.
Ohio Supreme Court Decision - On May 3, 2006, the Beaver Valley Unit 2 and Perry stations conducted nuclear refueling outages. Perry’s outage (including an unplanned extension) began on February 22, 2005 and continued intoOhio Supreme Court affirmed, in all but one aspect, the second quarter, ending on May 6, 2005. The Beaver Valley outage began on April 4, 2005 and ended on April 28, 2005.
On April 21, 2005, FENOC announced that it received a noticeprovisions of violation by the NRC and a proposed $5.45 million fineFirstEnergy's RSP for its Ohio customers. An issue related to the reactor head degradation at the Davis-Besse Nuclear Power Station. The corrosion on the plant’s reactor headcustomer pricing options was discovered during a comprehensive inspection and was reportedremanded to the NRCPUCO for further consideration. The Court found that FirstEnergy must provide an alternative market-based offering to customers in March 2002. Subsequently, FENOC investigatedaddition to that which they already have through their rate stabilization price, even if the causes ofalternative is higher than that offered through the problem, replaced the reactor head, and made numerous staff changes, as well as enhancements to plant programs and equipment. Davis-Besse has operated safely and reliably after successfully restarting in March 2004. The NRC said inRSP. On July 20, 2006, FirstEnergy filed a letter to FENOC that this action does not reflect the current performance of Davis-Besse and no further civil enforcement action is expected, absent any new information from the Department of Justice. On May 20, 2005, FENOC announced that it had been notified by the NRC that the Davis-Besse Nuclear Power Station would return to the standard NRC reactor oversight process, effective July 1, 2005. The NRC’s inspections of Davis-Besse are augmented to reflect commitments in a confirmatory order associated with the startup of the facility, and a previous NRC White Finding related to the performance of the emergency sirens.
FirstEnergy announced on May 18, 2005 that it had received approval from the PUCO to defer for future recovery charges from MISO incurred by FirstEnergy’s Ohio Companies. The deferred charges for 2005 are related to MISO’s administrative operation of FirstEnergy’s transmission systems and the daily and hourly spot energy market. A request filednotice with the PUCO to recoveraddress this issue through a proposed RFP program under which Ohio customers would have the opportunity to switch to alternative generation suppliers at prices established through the RFP program. FirstEnergy also provided notice of potential termination of certain portions of the RSP in the event that the issue is not resolved within a reasonable time frame or if modifications to the RSP are not acceptable. On July 26, 2006, the PUCO directed FirstEnergy to file within 45 days its plan to address the Court’s concern.
Pennsylvania Rate Matters - On May 31, 2006, the ALJ in the Met-Ed and Penelec rate transition plan filing established a procedural schedule with a goal of reaching a recommended decision in this proceeding by November 8, 2006. In accordance with this schedule, intervening parties submitted their written testimony by July 10, 2006. Ten public input hearings were held in various locations throughout the Met-Ed and Penelec service areas between June 20, 2006 and July 20, 2006.
Met-Ed and Penelec Transmission Charges - On May 4, 2006, the PPUC granted authority for Met-Ed and Penelec to defer, for accounting and financial reporting purposes, certain incremental transmission charges during 2006. The PPUC order allows Met-Ed and Penelec to defer, commencing January 1, 2006, the costs that are incremental to the levels currently reflected in the transmission component of Met-Ed’s and Penelec’s base rate tariffs. Recovery of the deferred costs will be considered in their pending comprehensive rate transition plan filing. Penn RFP - On June 2, 2006, the PPUC approved the bid results for the first bid. On July 18, 2006, the second PLR bid process was held for Penn. On July 20, 2006, the PPUC approved the submissions for the second bid. As a result of bids one and two, supply has been successfully acquired for all seven tranches of the Residential Group and all six of the Small Commercial Group. However, supply has only been acquired for three of the five tranches for the Large Commercial Group. Therefore, a residual third bid is scheduled to be held on August 15, 2006 for the two remaining Large Commercial Group tranches. Environmental Update - In June 2006, FirstEnergy finalized its air quality compliance strategy for 2006 through 2011. The program, which is expected to cost approximately $1.7 billion with the majority of those expenditures occurring between 2007 and 2009, is consistent with previous estimates and assumptions reflected in FirstEnergy’s long-term financial planning for air and water quality and other environmental matters. Share Repurchase Program - On June 20, 2006, FirstEnergy's Board of Directors authorized a share repurchase program for up to 12 million shares of common stock. At management’s discretion, shares may be acquired on the open market or through privately negotiated transactions, subject to market conditions and other factors. The Board’s authorization of the repurchase program does not require FirstEnergy to purchase any shares and the program may be terminated at any time. The 12 million shares represent 3.6% of the approximately 330 million shares of common stock currently outstanding. OE Senior Notes Offering - On June 26, 2006, OE issued $600 million of unsecured senior notes, comprised of $250 million due 2016 and $350 million due 2036. Proceeds from these charges overofferings were used in July 2006 to repurchase $500 million of OE’s common stock from FirstEnergy, to redeem $61 million of OE’s preferred stock and to reduce short-term debt. FirstEnergy primarily used the proceeds to redeem, on July 31, 2006, $400 million principal amount of its $1 billion, 5.5% Notes, Series A, in advance of the November 15, 2006 maturity date. This represents an important part of FirstEnergy’s 2006 financing strategy to obtain additional financing flexibility at the holding company level and to capitalize its regulated utilities more appropriately from a five-yearregulatory context. JCP&L Senior Notes Offering - On May 12, 2006, JCP&L issued $200 million of 6.40% secured Senior Notes due 2036. The proceeds of the offering were used to repay at maturity $150 million aggregate principal amount of JCP&L’s 6.45% Senior Notes due May 15, 2006 and for general corporate purposes. JCP&L Securitization - On June 8, 2006, the NJBPU approved JCP&L's request to issue securitization bonds associated with BGS stranded cost deferrals. On August 4, 2006, JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, secured pricing on the issuance of $182 million of transition bonds with a weighted average interest rate of 5.5%. New Coal Supply Agreement - On June 22, 2006, FGCO entered into a new coal supply agreement with CONSOL Energy, Inc. under which CONSOL will supply a total of more than 128 million tons of high-Btu coal to FirstEnergy for a 20-year period beginning in 2009. The new agreement replaces an existing coal supply agreement that took effect in January 2003 and ran through 2020. Under the new agreement, CONSOL will increase its coal shipments by approximately 2 million tons per year.
Ratified Contract Agreements - On May 11, 2006, is pending.
FirstEnergy’s JCP&L subsidiary announced on May 25, 2005, thatemployees represented by Local 270 of the NJBPU approvedUtility Workers Union of America (UWUA) voted to ratify a stipulated agreement with the NJPBU stafffive-year contract agreement. UWUA Local 270 represents approximately 1,075 linemen, substation electricians, meter readers, and the Division of Ratepayer Advocate resolving JCP&L’s Phase II rate case filing which resultedsupport personnel in the one-time gain discussed above, and a second stipulated settlement agreement with the NJBPU staff resolving the motion for reconsideration of the 2003 decision in its Phase I rate proceeding.
Together, the two stipulated settlements resulted in a net average increase, effective June 1, 2005, of approximately $1.14 per month in the delivery portion of the bill for residential customers using 500 KWH of electricity. The increase, averaging 2.4% per customer, is JCP&L’s first since 1993, and follows an 11% decrease implemented between 1999 and 2003 under New Jersey’s Electric Discount and Energy Competition Act. The stipulated settlements, which are expected to increase JCP&L’s annual revenues by approximately $51 million, include a commitment by JCP&L to maintain a target level of customer service reliability.
greater Cleveland area. On May 27, 2005, FirstEnergy’s Ohio Companies filed with26, 2006, employees of Penelec represented by the PUCOInternational Brotherhood of Electrical Workers (IBEW) Local 459 ratified a request to establish a generation charge adjustment factor, as permitted under the Ohio Companies’ previously approved Rate Stabilization Plan. If approved, the rider would average $0.002554 per KWH, effective January 1, 2006, for all classes of customers. The filing reflects projected increases in fuelthree-year collective bargaining agreement. IBEW Local 459 includes 482 linemen, substation electricians, meter readers and related costs in 2006 compared with 2002 costs.support personnel.
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 where the utility subsidiaries operate.
· | Regulated Services transmits, distributes and sells 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.
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· | Power Supply ManagementServices 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 segment 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.
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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 customers primarily in Ohio, Pennsylvania, Maryland 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.
Other operating segments provide a wide range of services, including heating, ventilation, air-conditioning, refrigeration, 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 to the consolidated financial statements.4). The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as "reportable segments"“reportable operating segments”.
FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS On May 13, In 2005, Penn,the Ohio Companies and on May 18, 2005, OE, CEI and TE,Penn entered into certain agreements described below (Agreements) implementing a series of intra-system generation asset transfers. When concluded,transfers that were completed in the fourth quarter of 2005. The asset transfers will resultresulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear fossil and hydroelectric plantsnon-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests that are being 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 are being undertaken in connection withwere 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. FENOC, a subsidiary of FirstEnergy, currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a master facility lease, leases the non-nuclear generation assets to be transferred and operates and maintains those assets. The transactions will essentially completecompleted the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO respectively, without impacting the operation of the plants. The transfers were intercompany transactions and, therefore, had no impact on FirstEnergy’s consolidated results.
34 As contemplated by the Agreements, the Ohio Companies and Penn intend to transfer their respective interests in the nuclear generation assets to NGC through, in the case of OE and Penn, a spin-off by way of a dividend and, in the case of CEI and TE, a sale at net book value. FGCO intends to exercise a purchase option under the Master Lease to acquire the non-nuclear generation assets to be transferred by the Ohio Companies at the values approved in the Ohio transition case.
Consummation of the transactions contemplated by each of the Agreements is subject to receipt of all necessary regulatory authorizations and other consents and approvals. FirstEnergy currently expects to complete the various asset transfers in the second half of 2005.
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 1613 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 1613 to the consolidated financial statements. Net income (loss) by major business segment was as follows:
| | | | | Three Months Ended | | | Six Months Ended | | | | | | | | June 30, | | Increase | | June 30, | | Increase | | | | | | | 2005 | | 2004 | | (Decrease) | | 2005 | | 2004 | | (Decrease) | | | | | | | (In millions, except per share amounts) | | Net Income (Loss) | | | | | | | | | | | | | | | | By Business Segment: | | | | | | | | | | | | | | | | | Regulated Services | | | | | $ | 267 | | $ | 234 | | $ | 33 | | $ | 490 | | $ | 446 | | $ | 44 | | | Power supply management services | | | | | | 11 | | | 37 | | | (26 | ) | | (25 | ) | | 36 | | | (61 | ) | | Other and reconciling adjustments* | | | | | | (100 | ) | | (67 | ) | | (33 | ) | | (127 | ) | | (104 | ) | | (23 | ) | | Total | | | | | $ | 178 | | $ | 204 | | $ | (26 | ) | $ | 338 | | $ | 378 | | $ | (40 | ) | | | | | | | | | | | | | | | | | | | | | | | | | Basic Earnings Per Share: | | | | | | | | | | | | | | | | | | | | | | | | Income before discontinued operations | | | | | | $0.54 | | | $0.61 | | | $ (0.07 | ) | | $0.98 | | | $1.15 | | | $ (0.17 | ) | | Discontinued operations | | | | | | - | | | 0.01 | | | (0.01 | ) | | 0.05 | | | 0.01 | | | 0.04 | | | Net earnings per basic share | | | | | | $0.54 | | | $0.62 | | | $ (0.08 | ) | | $1.03 | | | $1.16 | | | $ (0.13 | ) | | | | | | | | | | | | | | | | | | | | | | | | | Diluted Earnings Per Share: | | | | | | | | | | | | | | | | | | | | | | | | Income before discontinued operations | | | | | | $0.54 | | | $0.61 | | | $ (0.07 | ) | | $0.97 | | | $1.14 | | | $ (0.17 | ) | | Discontinued operations | | | | | | - | | | 0.01 | | | (0.01 | ) | | 0.05 | | | 0.01 | | | 0.04 | | | Net earnings per diluted share | | | | | | $0.54 | | | $0.62 | | | $ (0.08 | ) | | $1.02 | | | $1.15 | | | $ (0.13 | ) | | | | | | | | | | | | | | | | | | | | | | | | | * Represents other operating segments and reconciling items including interest expense on holding company debt and corporate support services revenues and expenses. | |
| | | | | Three Months Ended June 30, | | Six Months Ended June 30, | | | | | | | | | Increase | | | | Increase | | | | | | | 2006 | | 2005 | | (Decrease) | | 2006 | | 2005 | | (Decrease) | | | | | | | (In millions, except per share amounts) | | Net Income (Loss) | | | | | | | | | | | | | | | | By Business Segment: | | | | | | | | | | | | | | | | | Regulated Services | | | | | $ | 229 | | $ | 288 | | $ | (59 | ) | $ | 440 | | $ | 524 | | $ | (84 | ) | | Power supply management services | | | | | | 135 | | | (5 | ) | | 140 | | | 175 | | | (51 | ) | | 226 | | | Other and reconciling adjustments* | | | | | | (60 | ) | | (105 | ) | | 45 | | | (90 | ) | | (135 | ) | | 45 | | | Total | | | | | $ | 304 | | $ | 178 | | $ | 126 | | $ | 525 | | $ | 338 | | $ | 187 | | | | | | | | | | | | | | | | | | | | | | | | | | Basic Earnings Per Share: | | | | | | | | | | | | | | | | | | | | | | | | Income before discontinued operations | | | | | $ | 0.92 | | $ | 0.54 | | $ | 0.38 | | $ | 1.59 | | $ | 0.98 | | $ | 0.61 | | | Discontinued operations | | | | | | - | | | - | | | - | | | - | | | 0.05 | | | (0.05 | ) | | Net earnings per basic share | | | | | $ | 0.92 | | $ | 0.54 | | $ | 0.38 | | $ | 1.59 | | $ | 1.03 | | $ | 0.56 | | | | | | | | | | | | | | | | | | | | | | | | | | Diluted Earnings Per Share: | | | | | | | | | | | | | | | | | | | | | | | | Income before discontinued operations | | | | | $ | 0.91 | | $ | 0.54 | | $ | 0.37 | | $ | 1.58 | | $ | 0.97 | | $ | 0.61 | | | Discontinued operations | | | | | | - | | | - | | | - | | | - | | | 0.05 | | | (0.05 | ) | | Net earnings per diluted share | | | | | $ | 0.91 | | $ | 0.54 | | $ | 0.37 | | $ | 1.58 | | $ | 1.02 | | $ | 0.56 | | | | | | | | | | | | | | | | | | | | | | | | | |
| * | Represents other operating segments and reconciling items including interest expense on holding company debt and corporate support services revenues and expenses. |
EarningsNet income in the second quarter and the first six months of 2006 included net losses associated with the sale and impairment of non-core assets of $9 million (or $0.03 per share) and $11 million (or $0.03 per share), respectively.
Net income in the second quarter of 2005 included a net gain resulting from the JCP&L rate settlement of $16 million (or $0.05 per share) and additional income tax expense of $72$71 million (or $0.22 per share) from the enactment of new Ohio tax legislation. This compares to the second quarter of 2004 which included a loss from the sale of GLEP of approximately $7 million ($0.02 per share) and a litigation settlement loss of $11 million ($0.03 per share).legislation in Ohio. In addition to the second quarter items, net income in the first six months of 2005, included $22 million ($0.07net income was also increased by $0.02 per share)share from the combined impact of $0.07 per share of gains from the dispositionsale of non-core assets, an EPAoffset by $0.04 per share of expense associated with the W. H. Sammis Plant New Source Review settlement lossand $0.01 per share of $14 million ($0.04 per share) and an NRC fine of $3 million ($0.01 per share).
A decrease in wholesale electric revenues and purchased power costs in the second quarter and first six months of 2005 from the corresponding periods last year primarily 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 resulted from the dedication of FirstEnergy’s Beaver Valley Power Station to PJM in January 2005. FirstEnergy believes that a net-hourly-position measure of revenues and purchased power transactions is required as these generation assets are now dedicated in PJM where FirstEnergy has third-party customers. Wholesale electric revenues and purchased power costs in the second quarter of 2004 each included $283 million from these transactions recorded on a gross basis — the first six months of 2004 included $564 million from these transactions.
Excluding the effect of recording the wholesale electric revenue transactions in PJM on a gross basis in 2004, operating revenues in the second quarter and first six months of 2005 increased, reflecting in large part warmer than normal temperatures in the second quarter of 2005. Net income in the regulated services segment increased dueexpense related to the additional demand. However, net income forfine by the power supply management services segment was lower in bothNRC regarding the second quarter and first six months of 2005 as a result of higher costs for fossil fuel, purchased power and nuclear refueling costs which, in aggregate, more than offset the revenue from increased electric generation sales. The impact of the new Ohio tax legislation is included with FirstEnergy’s other operating segments and reconciling adjustments.Davis-Besse Nuclear Power Station.
Summary of Results of Operations - Second Quarter of 20052006 Compared with the Second Quarter of 20042005
Financial results for FirstEnergy and itsFirstEnergy's major business segments in the second quarter of 20052006 and 20042005 were as follows:
| | | | | Power | | | | | | | | | | | Supply | | Other and | | | | 2nd Quarter 2005 | | Regulated | | Management | | Reconciling | | FirstEnergy | | Quarterly Financial Results | | Services | | Services | | Adjustments | | Consolidated | | | | | (In millions) | | | Revenue: | | | | | | | | | | | External | | | | | | | | | | | Electric | | $ | 1,165 | | $ | 1,314 | | $ | - | | $ | 2,479 | | | Other | | | 186 | | | 65 | | | 199 | | | 450 | | | Internal | | | 80 | | | - | | | (80 | ) | | - | | | Total Revenues | | | 1,431 | | | 1,379 | | | 119 | | | 2,929 | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | Fuel and purchased power | | | - | | | 933 | | | - | | | 933 | | | Other operating | | | 408 | | | 399 | | | 106 | | | 913 | | | Provision for depreciation | | | 135 | | | 7 | | | 6 | | | 148 | | | Amortization of regulatory assets | | | 307 | | | - | | | - | | | 307 | | | Deferral of new regulatory assets | | | (120 | ) | | - | | | - | | | (120 | ) | | General taxes | | | 149 | | | 14 | | | 4 | | | 167 | | | Total Expenses | | | 879 | | | 1,353 | | | 116 | | | 2,348 | | | | | | | | | | | | | | | | | | Net interest charges | | | 99 | | | 8 | | | 54 | | | 161 | | | Income taxes | | | 186 | | | 7 | | | 48 | | | 241 | | | Income before discontinued operations | | | 267 | | | 11 | | | (99 | ) | | 179 | | | Discontinued operations | | | - | | | - | | | (1 | ) | | (1 | ) | | Net Income (Loss) | | $ | 267 | | $ | 11 | | $ | (100 | ) | $ | 178 | |
| | | | | Power | | | | | | | | | | | Supply | | Other and | | | | | | | Regulated | | Management | | Reconciling | | FirstEnergy | | 2nd Quarter 2006 Financial Results | | Services | | Services | | Adjustments | | Consolidated | | | | | (In millions) | | | Revenues: | | | | | | | | | | | External | | | | | | | | | | | Electric | | $ | 913 | | $ | 1,640 | | $ | - | | $ | 2,553 | | | Other | | | 132 | | | 38 | | | 63 | | | 233 | | | Internal | | | - | | | - | | | - | | | - | | | Total Revenues | | | 1,045 | | | 1,678 | | | 63 | | | 2,786 | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | Fuel and purchased power | | | - | | | 992 | | | - | | | 992 | | | Other operating expenses | | | 283 | | | 406 | | | 71 | | | 760 | | | Provision for depreciation | | | 88 | | | 50 | | | 6 | | | 144 | | | Amortization of regulatory assets | | | 195 | | | 4 | | | - | | | 199 | | | Deferral of new regulatory assets | | | (55 | ) | | (90 | ) | | - | | | (145 | ) | | General taxes | | | 129 | | | 39 | | | 5 | | | 173 | | | Total Expenses | | | 640 | | | 1.401 | | | 82 | | | 2,123 | | | | | | | | | | | | | | | | | | Operating Income (Loss) | | | 405 | | | 277 | | | (19 | ) | | 663 | | | Other Income (Expense): | | | | | | | | | | | | | | | Investment income | | | 75 | | | 2 | | | (46 | ) | | 31 | | | Interest expense | | | (96 | ) | | (56 | ) | | (26 | ) | | (178 | ) | | Capitalized interest | | | 5 | | | 2 | | | - | | | 7 | | | Subsidiaries' preferred stock dividends | | | (5 | ) | | - | | | 3 | | | (2 | ) | | Total Other Income (Expense) | | | (21 | ) | | (52 | ) | | (69 | ) | | (142 | ) | | | | | | | | | | | | | | | | | Income taxes (benefit) | | | 155 | | | 90 | | | (28 | ) | | 217 | | | Income before discontinued operations | | | 229 | | | 135 | | | (60 | ) | | 304 | | | Discontinued operations | | | - | | | - | | | - | | | - | | | Net Income (Loss) | | $ | 229 | | $ | 135 | | $ | (60 | ) | $ | 304 | |
| | | | | | | Power | | | | | | | | | Power | | | | | | | | | | | | | Supply | | Other and | | | | | | | Supply | | Other and | | | | 2nd Quarter 2004 | | | | Regulated | | Management | | Reconciling | | FirstEnergy | | | Quarterly Financial Results | | | | Services | | Services | | Adjustments | | Consolidated | | | | | | | | (In millions) | | | Regulated | | Management | | Reconciling | | FirstEnergy | | | Revenue: | | | | | | | | | | | | | 2nd Quarter 2005 Financial Results | | | Services | | Services | | Adjustments | | Consolidated | | | | | | (In millions) | | | Revenues: | | | | | | | | | | | | External | | | | | | | | | | | | | | | | | | | | | | Electric | | | | | $ | 1,125 | | $ | 1,520 | | $ | - | | $ | 2,645 | | | $ | 1,087 | | $ | 1,391 | | $ | - | | $ | 2,478 | | | Other | | | | | 153 | | | 30 | | | 164 | | | 347 | | | | 139 | | | 25 | | | 201 | | | 365 | | | Internal | | | | | | 80 | | | - | | | (80 | ) | | - | | | | 80 | | | - | | | (80 | ) | | - | | | Total Revenues | | | | | | 1,358 | | | 1,550 | | | 84 | | | 2,992 | | | | 1,306 | | | 1,416 | | | 121 | | | 2,843 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fuel and purchased power | | | | | - | | | 1,095 | | | - | | | 1,095 | | | | - | | | 933 | | | - | | | 933 | | | Other operating | | | | | 375 | | | 355 | | | 101 | | | 831 | | | | Other operating expenses | | | | 297 | | | 469 | | | 107 | | | 873 | | | Provision for depreciation | | | | | 127 | | | 9 | | | 10 | | | 146 | | | | 138 | | 4 | | | 7 | | | 149 | | | Amortization of regulatory assets | | | | | 271 | | | - | | | - | | | 271 | | | | 306 | | | - | | | - | | | 306 | | | Deferral of new regulatory assets | | | | | (68 | ) | | - | | | - | | | (68 | ) | | | (100 | ) | | (20 | ) | | - | | | (120 | ) | | General taxes | | | | | | 135 | | | 18 | | | 5 | | | 158 | | | | 132 | | | 31 | | | 5 | | | 168 | | | Total Expenses | | | | | | 840 | | | 1,477 | | | 116 | | | 2,433 | | | | 773 | | | 1,417 | | | 119 | | | 2,309 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net interest charges | | | | | 113 | | | 10 | | | 57 | | | 180 | | | | Income taxes | | | | | | 171 | | | 26 | | | (20 | ) | | 177 | | | | Operating Income (Loss) | | | | 533 | | | (1 | ) | | 2 | | | 534 | | | Other Income (Expense): | | | | | | | | | | | | | | | | Investment income | | | | 47 | | | - | | | - | | | 47 | | | Interest expense | | | | (99 | ) | | (10 | ) | | (53 | ) | | (162 | ) | | Capitalized interest | | | | 4 | | | 1 | | | - | | | 5 | | | Subsidiaries' preferred stock dividends | | | | (4 | ) | | - | | | - | | | (4 | ) | | Total Other Income (Expense) | | | | (52 | ) | | (9 | ) | | (53 | ) | | (114 | ) | | | | | | | | | | | | | | | | | | Income taxes (benefit) | | | | 193 | | | (5 | ) | | 53 | | | 241 | | | Income before discontinued operations | | | | | 234 | | | 37 | | | (69 | ) | | 202 | | | | 288 | | | (5 | ) | | (104 | ) | | 179 | | | Discontinued operations | | | | | | - | | | - | | | 2 | | | 2 | | | | - | | | - | | | (1 | ) | | (1 | ) | | Net Income (Loss) | | | | | $ | 234 | | $ | 37 | | $ | (67 | ) | $ | 204 | | | $ | 288 | | $ | (5 | ) | $ | (105 | ) | $ | 178 | |
Change Between | | | | | | Power | | | | | | | 2nd Quarter 2005 and 2004 | | | | | | Supply | | Other and | | | | | Quarterly Financial Results | | | | Regulated | | Management | | Reconciling | | FirstEnergy | | | | | | | | | Power | | | | | | Change Between 2nd Quarter 2006 and | | | | | Supply | | Other and | | | | 2nd Quarter 2005 Financial Results | | | Regulated | | Management | | Reconciling | | FirstEnergy | | Increase (Decrease) | | | | Services | | Services | | Adjustments | | Consolidated | | | Services | | Services | | Adjustments | | Consolidated | | | | | | | (In millions) | | | (In millions) | | | Revenue: | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | External | | | | | | | | | | | | | | | | | | | | | | Electric | | | | | $ | 40 | | $ | (206 | ) | $ | - | | $ | (166 | ) | | $ | (174 | ) | $ | 249 | | $ | - | | $ | 75 | | | Other | | | | | 33 | | 35 | | 35 | | | 103 | | | | (7 | ) | | 13 | | | (138 | ) | | (132 | ) | | Internal | | | | | | - | | | - | | | - | | | - | | | | (80 | ) | | - | | | 80 | | | - | | | Total Revenues | | | | | | 73 | | | (171 | ) | | 35 | | | (63 | ) | | | (261 | ) | | 262 | | | (58 | ) | | (57 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fuel and purchased power | | | | | - | | (162 | ) | | - | | | (162 | ) | | | - | | | 59 | | | - | | | 59 | | | Other operating | | | | | 33 | | 44 | | 5 | | | 82 | | | | Other operating expenses | | | | (14 | ) | | (63 | ) | | (36 | ) | | (113 | ) | | Provision for depreciation | | | | | 8 | | (2 | ) | | (4 | ) | | 2 | | | | (50 | ) | | 46 | | | (1 | ) | | (5 | ) | | Amortization of regulatory assets | | | | | 36 | | - | | - | | | 36 | | | | (111 | ) | | 4 | | | - | | | (107 | ) | | Deferral of new regulatory assets | | | | | (52 | ) | | - | | - | | | (52 | ) | | | 45 | | | (70 | ) | | - | | | (25 | ) | | General taxes | | | | | | 14 | | | (4 | ) | | (1 | ) | | 9 | | | | (3 | ) | | 8 | | | - | | | 5 | | | Total Expenses | | | | | | 39 | | | (124 | ) | | - | | | (85 | ) | | | (133 | ) | | (16 | ) | | (37 | ) | | (186 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net interest charges | | | | | (14 | ) | | (2 | ) | | (3 | ) | | (19 | ) | | | Operating Income | | | | (128 | ) | | 278 | | | (21 | ) | | 129 | | | Other Income (Expense): | | | | | | | | | | | | | | | | Investment income | | | | 28 | | | 2 | | | (46 | ) | | (16 | ) | | Interest expense | | | | 3 | | | (46 | ) | | 27 | | | (16 | ) | | Capitalized interest | | | | 1 | | | 1 | | | - | | | 2 | | | Subsidiaries' preferred stock dividends | | | | (1 | ) | | - | | | 3 | | | 2 | | | Total Other Income (Expense) | | | | 31 | | | (43 | ) | | (16 | ) | | (28 | ) | | | | | | | | | | | | | | | | | | Income taxes | | | | | | 15 | | | (19 | ) | | 68 | | | 64 | | | | (38 | ) | | 95 | | | (81 | ) | | (24 | ) | | Income before discontinued operations | | | | | 33 | | (26 | ) | | (30 | ) | | (23 | ) | | | (59 | ) | | 140 | | | 44 | | | 125 | | | Discontinued operations | | | | | | - | | | - | | | (3 | ) | | (3 | ) | | | - | | | - | | | 1 | | | 1 | | | Net Income (Loss) | | | | | $ | 33 | | $ | (26 | ) | $ | (33 | ) | $ | (26 | ) | | | Net Income | | | $ | (59 | ) | $ | 140 | | $ | 45 | | $ | 126 | | | | | | | | | | | | | | | |
Regulated Services - Second Quarter 20052006 Compared withto Second Quarter 20042005
Net income increaseddecreased $59 million (20.5%) to $267$229 million from $234in the second quarter of 2006 compared to $288 million (or 14%) in the second 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 | | | | | | June 30, | | Increase | | Revenues by Type of Service | | 2005 | | 2004 | | (Decrease) | | | | | (In millions) | | | | | | | | | | | Distribution services | | $ | 1,165 | | $ | 1,125 | | $ | 40 | | | Transmission services | | | 105 | | | 65 | | | 40 | | | Lease revenue from affiliates | | | 80 | | | 80 | | | - | | | Other | | | 81 | | | 88 | | | (7 | ) | | Total Revenues | | $ | 1,431 | | $ | 1,358 | | $ | 73 | |
Changes in distribution deliveries by customer class in the second quarter of 2005 are summarized in the following table:
| | | | Increase
| | Electric Distribution Deliveries
| | | | (Decrease)
| | Residential | | | | | | 9.5 | % | Commercial | | | | | | 2.9 | % | Industrial | | | | | | (3.8 | )% | Total Distribution Deliveries | | | | | | 2.4 | % | | | | | | | | |
Increased consumption offset in part by lower prices resulted in higher distribution delivery revenue. The following table summarizes major factors contributing to the $40 million increase in distribution services revenue in the second quarter of 2005:
| | | Increase | | Sources of Change in Distribution Revenues | | (Decrease) | | | | | (In millions) | | | | | | | | Changes in customer usage | | $ | 52 | | | Changes in prices: | | | | | | Rate changes -- | | | | | Ohio shopping incentive | | | (11 | ) | Other | | | (1 | ) | | Net Increase in Distribution Revenues | | $ | 40 | |
Distribution revenues benefited from warmer than normal temperatures in the second quarter of 2005 that increased the air-conditioning load of residential and commercial customers. Reduced industrial demand as a result of a softening in the automotive and steel-related sectors offset part of the weather-induced increase in load. A reduction in prices primarily resulted from additional credits provided to customers under the Ohio transition plan - those changes do not affect current period earnings due to deferral of the incentives for future recovery from customers.
Transmission revenues increased $40 million in the second quarter of 2005 from the same period last year due in part to an amended power supply agreement with FES in June 2004. Other revenues decreased $7 million due in part to a reduction in JCP&L transition bond revenues.
Expenses-
The higher revenues discussed above were partially offset by the following increases in expenses:
·Higher transmission expenses of $42 million due in part to an amended power supply agreement with FES, which also increased revenue;
·Increased provision for depreciation of $8 million due to property additions;
·Additional amortization of regulatory assets of $36 million, principally due to increased amortization of Ohio transition costs;
| · | Increased general taxes of $14 million due to additional Pennsylvania gross receipts tax and the absence in 2005 of Pennsylvania property tax refunds recognized in the second quarter of 2004; and |
·Higher income taxes of $15 million due to increased taxable income.
Partially offsetting these higher costs were two factors:
·Additional deferral of regulatory assets of $52 million, primarily the PUCO-approved MISO administrative costs, JCP&L reliability improvements and related interest (see Note 14 - Regulatory Matters - Transmission; New Jersey); and
·Lower interest charges of $14 million resulting from debt and preferred stock redemptions and refinancings.
Power Supply Management Services - Second Quarter 2005 Compared with Second Quarter 2004
Net income for this segment decreased to $11 million in the second quarter of 2005 from $37 million in the same period last year. A decrease in the gross generation margin and higher non-fuel nuclear costs resulted in lower net income.
Generation Margin -
The gross generation margin in the second quarter of 2005 decreased by $44 million compared to the same period of 2004, as shown in the table below.
| | | Three Months Ended | | | | | | | June 30, | | | | Gross Generation Margin | | 2005 | | 2004 | | (Decrease) | | | | | (In millions) | | | Electric generation revenue | | $ | 1,314 | | $ | 1,520 | | $ | (206 | ) | | Fuel and purchased power costs | | | 933 | | | 1,095 | | | (162 | ) | | Gross generation margin | | $ | 381 | | $ | 425 | | $ | (44 | ) |
Excluding the effect of recording PJM sales and purchases of $283 million on a gross basis in 2004, electric generation revenues increased $77 million while fuel and purchased power costs increased $121 million in the second quarter of 2005. The higher fuel and purchased power costs primarily resulted from higher prices which more than offset the benefit of increased sales to the retail and wholesale markets.
Revenues -
Excluding the effect of the change in recording PJM wholesale transactions, electric generation revenues increased $77 million in the second quarter of 2005 compared to the same period of 2004 primarily as a result of a 1.5% increase in KWH sales and higher unit prices. The additional retail sales reduced energy available for sale to the wholesale market resulting in a 0.9% reduction in those sales (before the PJM adjustment). Overall, revenues to the wholesale market increased due to a 7% rise in prices.
The change in reported segment revenues resulted from the following sources:
| | | Three Months Ended | | | | | | | June 30, | | Increase | | Revenues by Type of Service | | 2005 | | 2004 | | (Decrease) | | | | | (In millions) | | | Electric generation sales: | | | | | | | | | Retail | | $ | 989 | | $ | 930 | | $ | 59 | | | Wholesale | | | 325 | | | 307 | | | 18 | | | Total electric generation sales | | | 1,314 | | | 1,237 | | | 77 | | | Transmission | | | 15 | | | 23 | | | (8 | ) | | Other | | | 50 | | | 7 | | | 43 | | | Total | | | 1,379 | | | 1,267 | | | 112 | | | PJM gross transactions | | | - | | | 283 | | | (283 | ) | | Total Revenues | | $ | 1,379 | | $ | 1,550 | | $ | (171 | ) | | | | | | | | | | | | |
Changes in KWH sales are summarized in the following table:
Electric Generation
| | Increase
| | | (Decrease)
| | | | | Retail | | | 2.3 | % | Wholesale | | | (0.9 | )% | Total Electric Generation | | | 1.5 | %* | | | | | | * Decrease of 15.6% including the effect of the PJM revision. | | | | |
The other revenues increase in the second quarter of 2005 includes $40 million related to gas commodity operations. These transactions resulted from procuring fuel for gas-fired peaking capacity that was ultimately not required for generation and subsequently sold into the wholesale market. Related gas procurement costs of $38 million are reflected in the other operating costs in the second quarter of 2005.
Expenses -
Excluding the effect of the $283 million of PJM purchased power costs recorded on a gross basis in 2004, total operating expenses, net interest charges and income taxes increased in aggregate by $138 million in the second quarter of 2005 compared to the same period of 2004. Higher fuel and purchased power costs contributed $121 million ($162 million, net of $283 million PJM effect) of the increase, resulting from higher fuel costs of $89 million and increased purchased power costs of $32 million. Factors contributing to the higher costs are summarized in the following table:
| | | Increase | | Source of Change in Fuel and Purchased Power | | (Decrease) | | | | | (In millions) | | | Fuel: | | | | | Change due to price | | $ | 65 | | Change due to volume | | | 24 | | | | | | 89 | | | Purchased Power: | | | | Change due to price | | | 64 | | Change due to volume | | | (9 | ) | Deferred costs | | | (23 | ) | | | | | 32 | | | | | | | | | Net Increase in Fuel and Purchased Power Costs | | $ | 121 | | | | | | | |
FirstEnergy’s fleet of generating plants established a new output record of 19.1 billion KWH. Increased coal and emission allowance costs combined to increase fossil fuel expense. Higher coal costs resulted from increased purchases, market adjustment provisions in coal contracts reflecting higher market prices and increased transportation costs. Emission allowance costs increased primarily from higher prices. To a lesser extent, fuel expense increased due to the increased mix of fossil versus nuclear generation resulting in large part from the nuclear refueling outages in the second quarter of 2005 following a year with no scheduled nuclear outages. Fossil generation increased 12% in the second quarter of 2005 while nuclear generation decreased by 16%.
Non-fuel nuclear costs increased $33 million primarily due to costs from the Beaver Valley Unit 2 refueling outage (started April 4, 2005) and to a lesser extent from the Perry Unit 1 outage initiated in the first quarter of 2005 and completed May 6, 2005. There were no nuclear refueling outages in the second quarter of 2004.
Partially offsetting these higher costs were the following factors:
·Reduced non-fuel fossil generation expense of $7 million due to different maintenance outage schedules;
·Lower transmission costs of $10 million due in part to the 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 $19 million due to lower taxable income.
Other - Second Quarter 2005 Compared with Second Quarter 2004
FirstEnergy’s financial results from other operating segments and reconciling adjustments, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a net decrease in FirstEnergy’s net income in the second quarter of 2005 compared to the same quarter of 2004. The decrease was primarily due to the effect of the new Ohio tax legislation, partially offset by the absence in the second quarter of 2005 of a litigation settlement loss of $11 million and the after-tax loss on the sale of GLEP of $7 million recorded in the second quarter of 2004.
On June 30, 2005, the State of Ohio enacted new tax legislation that creates a new Commercial Activity Tax (CAT), which is based on qualifying "taxable gross receipts" and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax is effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and the personal property tax is phased-out over a four-year period at a rate of approximately 25% annually, beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The impact on income taxes associated with the required adjustment to net deferred taxes for the second quarter of 2005 was additional tax expense of approximately $72 million, which was partially offset by the initial phase-out of the Ohio income-based franchise tax, which reduced income taxes by approximately $8 million in the second quarter of 2005. See Note 12 to the consolidated financial statements.
Summary of Results of Operations - First Six Months of 2005 Compared with the First Six Months of 2004
Financial results for FirstEnergy and its major business segments for the first six months of 2005 and 2004 were as follows:
| | | | | | | Power | | | | | | | | | | | | | Supply | | Other and | | | | First Six Months of 2005 | | | | Regulated | | Management | | Reconciling | | FirstEnergy | | Financial Results | | | | Services | | Services | | Adjustments | | Consolidated | | | | | | | (In millions) | | | Revenue: | | | | | | | | | | | | | External | | | | | | | | | | | | | Electric | | | | | $ | 2,327 | | $ | 2,589 | | $ | - | | $ | 4,916 | | | Other | | | | | | 363 | | | 84 | | | 367 | | | 814 | | | Internal | | | | | | 158 | | | - | | | (158 | ) | | - | | | Total Revenues | | | | | | 2,848 | | | 2,673 | | | 209 | | | 5,730 | | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | Fuel and purchased power | | | | | | - | | | 1,828 | | | - | | | 1,828 | | | Other operating | | | | | | 826 | | | 807 | | | 172 | | | 1,805 | | | Provision for depreciation | | | | | | 261 | | | 17 | | | 14 | | | 292 | | | Amortization of regulatory assets | | | | | | 617 | | | - | | | - | | | 617 | | | Deferral of new regulatory assets | | | | | | (180 | ) | | - | | | - | | | (180 | ) | | General taxes | | | | | | 296 | | | 45 | | | 12 | | | 353 | | | Total Expenses | | | | | | 1,820 | | | 2,697 | | | 198 | | | 4,715 | | | | | | | | | | | | | | | | | | | | | Net interest charges | | | | | | 197 | | | 18 | | | 117 | | | 332 | | | Income taxes | | | | | | 341 | | | (17 | ) | | 39 | | | 363 | | | Income before discontinued operations | | | | | | 490 | | | (25 | ) | | (145 | ) | | 320 | | | Discontinued operations | | | | | | - | | | - | | | 18 | | | 18 | | | Net Income (Loss) | | | | | $ | 490 | | $ | (25 | ) | $ | (127 | ) | $ | 338 | | | | | | | | | | | | | | | | | | | |
| | | | | | | Power | | | | | | | | | | | | | Supply | | Other and | | | | First Six Months of 2004 | | | | Regulated | | Management | | Reconciling | | FirstEnergy | | Financial Results | | | | Services | | Services | | Adjustments | | Consolidated | | | | | | | (In millions) | | | Revenue: | | | | | | | | | | | | | External | | | | | | | | | | | | | Electric | | | | | $ | 2,279 | | $ | 3,022 | | $ | - | | $ | 5,301 | | | Other | | | | | | 289 | | | 50 | | | 335 | | | 674 | | | Internal | | | | | | 159 | | | - | | | (159 | ) | | - | | | Total Revenues | | | | | | 2,727 | | | 3,072 | | | 176 | | | 5,975 | | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | Fuel and purchased power | | | | | | - | | | 2,229 | | | - | | | 2,229 | | | Other operating | | | | | | 741 | | | 702 | | | 189 | | | 1,632 | | | Provision for depreciation | | | | | | 254 | | | 17 | | | 21 | | | 292 | | | Amortization of regulatory assets | | | | | | 581 | | | - | | | - | | | 581 | | | Deferral of new regulatory assets | | | | | | (113 | ) | | - | | | - | | | (113 | ) | | General taxes | | | | | | 283 | | | 42 | | | 12 | | | 337 | | | Total Expenses | | | | | | 1,746 | | | 2,990 | | | 222 | | | 4,958 | | | | | | | | | | | | | | | | | | | | | Net interest charges | | | | | | 219 | | | 21 | | | 111 | | | 351 | | | Income taxes | | | | | | 316 | | | 25 | | | (49 | ) | | 292 | | | Income before discontinued operations | | | | | | 446 | | | 36 | | | (108 | ) | | 374 | | | Discontinued operations | | | | | | - | | | - | | | 4 | | | 4 | | | Net Income (Loss) | | | | | $ | 446 | | $ | 36 | | $ | (104 | ) | $ | 378 | | | | | | | | | | | | | | | | | | | |
| | | | | | | Power | | | | | | Change Between | | | | | | Supply | | Other and | | | | First Six Months 2005 vs. 2004 | | | | Regulated | | Management | | Reconciling | | FirstEnergy | | Financial Results | | | | Services | | Services | | Adjustments | | Consolidated | | Increase (Decrease) | | | | (In millions) | | | Revenue: | | | | | | | | | | | | | External | | | | | | | | | | | | | Electric | | | | | $ | 48 | | $ | (433 | ) | $ | - | | $ | (385 | ) | | Other | | | | | | 74 | | | 34 | | | 32 | | | 140 | | | Internal | | | | | | (1 | ) | | - | | | 1 | | | - | | | Total Revenues | | | | | | 121 | | | (399 | ) | | 33 | | | (245 | ) | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | Fuel and purchased power | | | | | | - | | | (401 | ) | | - | | | (401 | ) | | Other operating | | | | | | 85 | | | 105 | | | (17 | ) | | 173 | | | Provision for depreciation | | | | | | 7 | | | - | | | (7 | ) | | - | | | Amortization of regulatory assets | | | | | | 36 | | | - | | | - | | | 36 | | | Deferral of new regulatory assets | | | | | | (67 | ) | | - | | | - | | | (67 | ) | | General taxes | | | | | | 13 | | | 3 | | | - | | | 16 | | | Total Expenses | | | | | | 74 | | | (293 | ) | | (24 | ) | | (243 | ) | | | | | | | | | | | | | | | | | | | | Net interest charges | | | | | | (22 | ) | | (3 | ) | | 6 | | | (19 | ) | | Income taxes | | | | | | 25 | | | (42 | ) | | 88 | | | 71 | | | Income before discontinued operations | | | | | | 44 | | | (61 | ) | | (37 | ) | | (54 | ) | | Discontinued operations | | | | | | - | | | - | | | 14 | | | 14 | | | Net Income (Loss) | | | | | $ | 44 | | $ | (61 | ) | $ | (23 | ) | $ | (40 | ) | | | | | | | | | | | | | | | | | | |
Regulated Services - First Six Months of 2005 Compared with First Six Months of 2004
Net income increased to $490 million in the first six months of 2005 from $446 million in the same period of 2004 due to increased operating revenues partially offset by higher operating expenses and taxes.
Revenues -
The increase in total revenues resulted from the following sources:
| | | Six Months Ended | | | | | Three Months Ended June 30, | | | | | June 30, | | Increase | | | | | Increase | | Revenues by Type of Service | | 2005 | | 2004 | | (Decrease) | | | | | | (In millions) | | | Revenues By Type of Service | | | 2006 | | 2005 | | (Decrease) | | | | | | | | | | | | (In millions) | | | Distribution services | | $ | 2,327 | | $ | 2,279 | | $ | 48 | | | $ | 913 | | $ | 1,087 | | $ | (174 | ) | | Transmission services | | | 197 | | 130 | | 67 | | | | 87 | | 105 | | (18 | ) | | Lease revenue from affiliates | | | 158 | | 159 | | (1 | ) | | | Internal lease revenues | | | | - | | 80 | | (80 | ) | | Other | | | 166 | | | 159 | | | 7 | | | | 45 | | | 34 | | | 11 | | | Total Revenues | | $ | 2,848 | | $ | 2,727 | | $ | 121 | | | $ | 1,045 | | $ | 1,306 | | $ | (261 | ) | | | | | | | | | | | |
Changes in distribution deliveries by customer class are summarized in the following table:
Electric Distribution Deliveries | | Increase
| | | | | | | Residential | | | 3.8(4.8 | )% | | Commercial | | | 3.8(1.1 | )% | | Industrial | | | 0.10.4 | % | | Total Distribution Deliveries | | | 2.5(1.8 | )% | | | | | |
Increased consumption offsetThe 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 decrease in deliveries to customers was primarily due to unseasonably milder weather during the second quarter of 2006. The following table summarizes major factors contributing to the $48$174 million increasedecrease in distribution services revenue in the first half of 2005:
| | | Increase | | Sources of Change in Distribution Revenues | | (Decrease) | | | | | (In millions) | | | | | | | | Changes in customer usage | | $ | 75 | | | Changes in prices: | | | | | | Rate changes - | | | | | | Ohio shopping incentive | | | (22 | ) | | Other | | | 8 | | | Rate mix and other | | | (13 | ) | | Net Increase in Distribution Revenues | | $ | 48 | | | | | | | |
Distributionservice revenues benefited from warmer than normal temperatures in the second quarter of 2005 that increased the air-conditioning load of residential and commercial customers. Sales to industrial customers were flat due in part to a softening in automotive and steel-related markets. A reduction in prices primarily resulted from additional shopping credits under the Ohio transition plan.2006:
Sources of Change in Distribution Revenues | | Increase (Decrease) | | | | | (In millions) | | | Changes in customer usage | | $ | (54 | ) | | Ohio shopping incentives | | | 58 | | | Changes in prices: | | | | | | Rate mix and other | | | (178 | ) | | | | | | | | Net Decrease in Distribution Revenues | | $ | (174 | ) |
TransmissionThe decrease in internal revenues increased $67 million inreflected the first six monthseffect of the generation asset transfers discussed above. The 2005 generation assets lease revenue from affiliates ceased as a result of the same period last year due in part to the amended power supply agreement with FES in June 2004. Other revenues increased $7 million primarily due to a payment received under a contract provision associated with the prior sale of TMI, which was offset in part by reduced JCP&L transition bond revenue.transfers.
Expenses-
The higherdecrease in revenues discussed above werewas partially offset by the following increasesdecreases in total expenses:
| · | Other operating expenses were $14 million lower in 2006 due, in part, to the following factors: |
· Higher transmission expenses of $85 million due in part to the amended power supply agreement with FES, which also increased revenue;
| 1) | The absence in 2006 of expenses for ancillary service refunds to third parties of $6 million in 2005 due to the RCP, which provides that alternate suppliers of ancillary services now bill customers directly for those services; |
· Increased provision for depreciation of $7 million reflecting the effect of property additions and additional costs for decommissioning the Saxton nuclear unit;
· Additional amortization of regulatory assets of $36 million, principally due to amortization of Ohio transition costs;
·2) | Increased general taxes of $13A $27 million related to additional Pennsylvania gross receipts taxdecrease in employee and contractor costs resulting from lower storm-related expenses, reduced employee benefits (principally postretirement benefits) and the absence in 2005decreased use of Pennsylvania property tax refunds recognized in the second quarter of 2004;outside contractors for tree trimming, reliability work, legal services and jobbing and contracting; and |
· Higher income taxes of $25 million due to increased taxable income.| 3) | An $18 million increase due in part to insurance premium costs, financing fees and other administrative costs. |
| · | Lower depreciation expense of $50 million that resulted from the impact of the generation asset transfers; |
| · | Reduced amortization of regulatory assets of $111 million principally due to the completion of Ohio generation transition cost recovery and Penn's transition plan in 2005; and |
| · | General taxes decreased by $3 million primarily due to lower property taxes as a result of the generation asset transfers. |
The reduction in the deferral of new regulatory assets resulted from the 2005 JCP&L rate decision and the end of shopping incentive deferrals under the Ohio Companies’ transition plan, partially offset by the distribution cost deferrals under the Ohio Companies’ RCP.
Partially offsetting these higher costs were two factors:Other Income -
·Additional deferral 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 second quarter of $67 million, primarily2006 was partially offset by the PUCO-approved MISO administrative costs, JCP&L reliability improvements, shopping incentive credits and related interest on those deferrals (see Note 14 - Regulatory Matters - Transmission, New Jersey); and
·Lower interest chargesabsence in 2006 of $22 million resulting from debt and preferred stock redemptions.the majority of nuclear decommissioning trust income which is now included in the power supply management services segment.
Power Supply Management Services - First Six Months ofSecond Quarter 2006 Compared to Second Quarter 2005 Compared with the First Six Months of 2004
The net loss Net income for this segment was $25$135 million in the first six monthssecond quarter of 20052006 compared to a net incomeloss of $36$5 million in the same period last year. A reductionAn improvement in the gross generation margin was partially offset by higher nuclear operating costsdepreciation, general taxes and amounts recognized for fines, penalties and obligations associated with proceedings involvinginterest expense resulting from the Sammis Plant and the Davis-Besse Nuclear Power Station produced the net loss.generation asset transfers.
Generation Margin -
The gross generation margin in the first six months of 2005 decreased by $32 million compared to the same period of 2004, as shown in the table below.
| | | Six Months Ended | | | | | | | June 30, | | | | Gross Generation Margin | | 2005 | | 2004 | | (Decrease) | | | | | (In millions) | | | | | | | | | | | | Electric generation revenue | | $ | 2,589 | | $ | 3,022 | | $ | (433 | ) | | Fuel and purchased power costs | | | 1,828 | | | 2,229 | | | (401 | ) | | Gross Generation Margin | | $ | 761 | | $ | 793 | | $ | (32 | ) | | | | | | | | | | | | |
Excluding the effect of PJM sales and purchases of $564 million recorded on a gross basis in 2004, electric generation revenues increased $131 million while fuel and purchased power costs increased $163 million. The higher fuel and purchased power costs primarily resulted from higher prices which more than offset the benefit of increased sales to retail and wholesale markets.
Revenues -
Excluding the effect of the change in recording PJM wholesale transactions, electric Electric generation sales revenues increased $131$224 million in the first six monthssecond quarter of 20052006 compared to the same period in 2005. This increase primarily resulted from a 7.7% increase in retail KWH sales, mostly due to the return of 2004customers as a result of a 0.9% increase in KWH salesthird-party suppliers leaving the Ohio marketplace, and higher unit prices.prices resulting from the 2006 rate stabilization and fuel recovery charges. Additional retail sales reduced energy available for sale to the wholesale market. Increased transmission revenues reflected new revenues of approximately $27 million under the MISO transmission rider that began in the first quarter of 2006.
The changeAn increase in reported segment revenues resulted from the following sources:
| | | Six Months Ended | | | | | | | June 30, | | Increase | | Revenues by Type of Service | | 2005 | | 2004 | | (Decrease) | | | | | (In millions) | | | | | | | | | | | | Electric generation sales: | | | | | | | | | Retail | | $ | 1,969 | | $ | 1,864 | | $ | 105 | | | Wholesale | | | 620 | | | 594 | | | 26 | | | Total Electric Generation Sales | | | 2,589 | | | 2,458 | | | 131 | | | Transmission | | | 25 | | | 37 | | | (12 | ) | | Other | | | 59 | | | 13 | | | 46 | | | Total | | | 2,673 | | | 2,508 | | | 165 | | | PJM gross transactions | | | - | | | 564 | | | (564 | ) | | Total Revenues | | $ | 2,673 | | $ | 3,072 | | $ | (399 | ) | | | | | | | | | | | | |
Changes in KWH sales are summarized in the following table:
| | Increase
| Electric Generation
| | (Decrease)
| Retail | | | 1.7 | % | Wholesale | | | (1.8 | )% | Total Electric Generation | | | 0.9 | %* | | | | | | * Decrease of 15.8% including the effect of the PJM revision. | | | | |
| | | Three Months Ended June 30, | | | | | | | Increase | | Revenues By Type of Service | | 2006 | | 2005 | | (Decrease) | | | | | (In millions) | | | Electric Generation Sales: | | | | | | | | | Retail | | $ | 1,285 | | $ | 989 | | $ | 296 | | | Wholesale | | | 253 | | | 325 | | | (72 | ) | | Total Electric Generation Sales | | | 1,538 | | | 1,314 | | | 224 | | | Transmission | | | 134 | | | 93 | | | 41 | | | Other | | | 6 | | | 9 | | | (3 | ) | | Total Revenues | | $ | 1,678 | | $ | 1,416 | | $ | 262 | |
The other revenues increasefollowing table summarizes the price and volume factors contributing to changes in the first six months of 2005 primarily resulted from the $40 million ofsales revenues from the gas commodity operations previously discussed in the second quarter 2005 results analysis.retail and wholesale customers:
| | | Increase | | Source of Change in Electric Generation Sales | | (Decrease) | | | | | (In millions) | | | Retail: | | | | | Effect of 7.7% increase in customer usage | | $ | 76 | | Increased prices | | | 220 | | | | | | 296 | | | Wholesale: | | | | | Effect of 8.4% decrease in KWH sales | | | (27 | ) | Lower prices | | | (45 | ) | | | | | (72 | ) | | Net Increase in Electric Generation Sales | | $ | 224 | |
Expenses -
Excluding the effect of the $564 million of PJM purchased power costs recorded on a gross basis in 2004, totalTotal operating expenses net interest charges and income taxes increased in aggregate by $226 million. Higher fuel and purchased power costs contributed $163 million of the increase, resulting from higher fuel costs of $123 million and increased purchased power costs of $40 million. Factors contributing to the higher costs are summarized in the following table:
| | | Increase | | Source of Change in Fuel and Purchased Power | | (Decrease) | | | | | (In millions) | | | | | | | | Fuel: | | | | | Change due to price | | $ | 88 | | Change due to volume | | | 35 | | | | | | 123 | | | | | | | | Purchased Power: | | | | Change due to price | | | 124 | | Change due to volume | | | (36 | ) | Deferred costs | | | (48 | ) | | | | | 40 | | | | | | | | | Net Increase in Fuel and Purchased Power Costs | | $ | 163 | | | | | | | |
FirstEnergy’s fleet of generating plants established a new output record of 37.9 billion KWH. Increased coal and emission allowance costs combined to increase fossil fuel expense. Higher coal costs resulted from increased purchases, market adjustment provisions in coal contracts reflecting higher market prices and increased transportation costs. Emission allowance costs increased primarily from higher prices. To a lesser extent, fuel expense increased due to the increased mix of fossil versus nuclear generation resulting in large part from the nuclear refueling outages in first six months of 2005 following a year with no scheduled nuclear outages. Fossil generation increased 10% in the first six months of 2005 while nuclear generation decreased by 14%.
Non-fuel nuclear costs increased $100 million$16 million. The decrease was due primarily to refueling outages at Perry Unit 1 (including an unplanned extension) and Beaver Valley Unit 2 and a scheduled 23-day mid-cycle inspection outage at the Davis-Besse nuclear plant. There were no scheduled nuclear outages in the first six months of 2004.
Partially offsetting these higher costs were the following factors:
| · | Lower non-fuel operating expenses of $63 million reflect the absence in 2006 of generating lease rents of $80 million in 2005 due to the generation asset transfers, partially offset by higher transmission expenses of $11 million related to the transmission revenues discussed above; and |
| · | The $70 million increase in the deferral of new regulatory assets represents PJM/MISO costs incurred that are expected to be recovered from customers through future rates. The recognition of these amounts under the Power Supply Management Services segment reflects a change in the current year operations reporting as discussed in Note 13 - Segment Information. Retail transmission revenues and PJM/MISO transmission revenues and expenses associated with serving electricity load are now included in the power supply management services segment results. The deferrals in 2006 also include the Ohio RCP fuel deferral of $29 million. |
·Reduced non-fuel fossil generation expense of $17 million due to different maintenance outage schedules;The above decreases were partially offset by the following:
·Lower transmission costs of $37 million due in part to the 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 | · | Higher fuel and purchased power costs of $59 million, including increased fuel costs of $23 million - coal costs increased $40 million as a result of increased generation output, higher coal commodity prices and increased transportation costs for western coal. The increased coal costs were partially offset by lower natural gas and emission allowance costs of $20 million. Purchased power costs increased $36 million due to higher prices and increased volumes. Factors producing the higher costs are summarized in the following table: |
·Lower income taxes of $42 million due to lower taxable income.| | | Increase | | Source of Change in Fuel and Purchased Power | | (Decrease) | | | | | (In millions) | | | Fuel: | | | | | Change due to increased unit costs | | $ | 5 | | Change due to volume consumed | | | 18 | | | | | | 23 | | | Purchased Power: | | | | | Change due to increased unit costs | | | 53 | | Change due to volume purchased | | | 2 | | Increase in NUG costs deferred | | | (19 | ) | | | | | 36 | | | | | | | | | Net Increase in Fuel and Purchased Power Costs | | $ | 59 | |
| · | Increased depreciation expenses of $46 million resulted principally from the generation asset transfers; and |
| · | Higher general taxes of $8 million due to additional property taxes resulting from the generation asset transfers. |
41Other Income and Expense -
| · | Investment income in the second quarter of 2006 increased by $2 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 that financed the generation asset transfers. |
Other - First Six Months ofSecond Quarter 2006 Compared to Second Quarter 2005 Compared with the First Six Months of 2004.
FirstEnergy’s financial results from other operating segments and reconciling adjustments,items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $45 million increase to FirstEnergy’s net income in the second quarter of 2006 compared to the same quarter of 2005. The increase was primarily due to the absence of an adjustment from the effect of Ohio tax legislation in June 2005, which resulted in additional 2005 tax expenses of $71 million, and a $3 million gain related to interest rate swap financing arrangements. These increases were partially offset by a $5 million reduction in investment income, non-core asset sales gains/impairments of $9 million and a $7 million reduction in gas commodity trading results.
Summary of Results of Operations - First Six Months of 2006 Compared with the First Six Months of 2005
Financial results for FirstEnergy's major business segments in the first six months of 2006 and 2005 were as follows:
| | | | | Power | | | | | | | | | | | Supply | | Other and | | | | | | | Regulated | | Management | | Reconciling | | FirstEnergy | | First Six Months of 2006 Financial Results | | Services | | Services | | Adjustments | | Consolidated | | | | | (In millions) | | | Revenues: | | | | | | | | | | | External | | | | | | | | | | | Electric | | $ | 1,848 | | $ | 3,216 | | $ | - | | $ | 5,064 | | | Other | | | 280 | | | 81 | | | 206 | | | 567 | | | Internal | | | - | | | - | | | - | | | - | | | Total Revenues | | | 2,128 | | | 3,297 | | | 206 | | | 5,631 | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | Fuel and purchased power | | | - | | | 1,990 | | | - | | | 1,990 | | | Other operating expenses | | | 582 | | | 856 | | | 215 | | | 1,653 | | | Provision for depreciation | | | 184 | | | 96 | | | 12 | | | 292 | | | Amortization of regulatory assets | | | 412 | | | 9 | | | - | | | 421 | | | Deferral of new regulatory assets | | | (110 | ) | | (116 | ) | | - | | | (226 | ) | | General taxes | | | 269 | | | 84 | | | 13 | | | 366 | | | Total Expenses | | | 1,337 | | | 2,919 | | | 240 | | | 4,496 | | | | | | | | | | | | | | | | | | Operating Income (Loss) | | | 791 | | | 378 | | | (34 | ) | | 1,135 | | | Other Income (Expense): | | | | | | | | | | | | | | | Investment income | | | 137 | | | 17 | | | (80 | ) | | 74 | | | Interest expense | | | (190 | ) | | (109 | ) | | (44 | ) | | (343 | ) | | Capitalized interest | | | 8 | | | 6 | | | - | | | 14 | | | Subsidiaries' preferred stock dividends | | | (7 | ) | | - | | | 3 | | | (4 | ) | | Total Other Income (Expense) | | | (52 | ) | | (86 | ) | | (121 | ) | | (259 | ) | | | | | | | | | | | | | | | | | Income taxes (benefit) | | | 299 | | | 117 | | | (65 | ) | | 351 | | | Income before discontinued operations | | | 440 | | | 175 | | | (90 | ) | | 525 | | | Discontinued operations | | | - | | | - | | | - | | | - | | | Net Income (Loss) | | $ | 440 | | $ | 175 | | $ | (90 | ) | $ | 525 | |
| | | | | Power | | | | | | | | | | | Supply | | Other and | | | | | | | Regulated | | Management | | Reconciling | | FirstEnergy | | First Six Months of 2005 Financial Results | | Services | | Services | | Adjustments | | Consolidated | | | | | (In millions) | | | Revenues: | | | | | | | | | | | External | | | | | | | | | | | Electric | | $ | 2,169 | | $ | 2,746 | | $ | - | | $ | 4,915 | | | Other | | | 273 | | | 47 | | | 358 | | | 678 | | | Internal | | | 158 | | | - | | | (158 | ) | | - | | | Total Revenues | | | 2,600 | | | 2,793 | | | 200 | | | 5,593 | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | Fuel and purchased power | | | - | | | 1,828 | | | - | | | 1,828 | | | Other operating expenses | | | 625 | | | 968 | | | 164 | | | 1,757 | | | Provision for depreciation | | | 261 | | | 17 | | | 14 | | | 292 | | | Amortization of regulatory assets | | | 617 | | | - | | | - | | | 617 | | | Deferral of new regulatory assets | | | (160 | ) | | (20 | ) | | - | | | (180 | ) | | General taxes | | | 274 | | | 67 | | | 12 | | | 353 | | | Total Expenses | | | 1,617 | | | 2,860 | | | 190 | | | 4,667 | | | | | | | | | | | | | | | | | | Operating Income (Loss) | | | 983 | | | (67 | ) | | 10 | | | 926 | | | Other Income (Expense): | | | | | | | | | | | | | | | Investment income | | | 88 | | | - | | | - | | | 88 | | | Interest expense | | | (194 | ) | | (16 | ) | | (116 | ) | | (326 | ) | | Capitalized interest | | | 7 | | | (3 | ) | | - | | | 4 | | | Subsidiaries' preferred stock dividends | | | (10 | ) | | - | | | - | | | (10 | ) | | Total Other Income (Expense) | | | (109 | ) | | (19 | ) | | (116 | ) | | (244 | ) | | | | | | | | | | | | | | | | | Income taxes (benefit) | | | 350 | | | (35 | ) | | 47 | | | 362 | | | Income before discontinued operations | | | 524 | | | (51 | ) | | (153 | ) | | 320 | | | Discontinued operations | | | - | | | - | | | 18 | | | 18 | | | Net Income (Loss) | | $ | 524 | | $ | (51 | ) | $ | (135 | ) | $ | 338 | |
| | | | | Power | | | | | | Change Between First Six Months of 2006 | | | | Supply | | Other and | | | | and First Six Months of 2005 | | Regulated | | Management | | Reconciling | | FirstEnergy | | Financial Results - Increase (Decrease) | | Services | | Services | | Adjustments | | Consolidated | | | | | (In millions) | | | Revenues: | | | | | | | | | | | External | | | | | | | | | | | Electric | | $ | (321 | ) | $ | 470 | | $ | - | | $ | 149 | | | Other | | | 7 | | | 34 | | | (152 | ) | | (111 | ) | | Internal | | | (158 | ) | | - | | | 158 | | | - | | | Total Revenues | | | (472 | ) | | 504 | | | 6 | | | 38 | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | Fuel and purchased power | | | - | | | 162 | | | - | | | 162 | | | Other operating expenses | | | (43 | ) | | (112 | ) | | 51 | | | (104 | ) | | Provision for depreciation | | | (77 | ) | | 79 | | | (2 | ) | | - | | | Amortization of regulatory assets | | | (205 | ) | | 9 | | | - | | | (196 | ) | | Deferral of new regulatory assets | | | 50 | | | (96 | ) | | - | | | (46 | ) | | General taxes | | | (5 | ) | | 17 | | | 1 | | | 13 | | | Total Expenses | | | (280 | ) | | 59 | | | 50 | | | (171 | ) | | | | | | | | | | | | | | | | | Operating Income | | | (192 | ) | | 445 | | | (44 | ) | | 209 | | | Other Income (Expense): | | | | | | | | | | | | | | | Investment income | | | 49 | | | 17 | | | (80 | ) | | (14 | ) | | Interest expense | | | 4 | | | (93 | ) | | 72 | | | (17 | ) | | Capitalized interest | | | 1 | | | 9 | | | - | | | 10 | | | Subsidiaries' preferred stock dividends | | | 3 | | | - | | | 3 | | | 6 | | | Total Other Income (Expense) | | | 57 | | | (67 | ) | | (5 | ) | | (15 | ) | | | | | | | | | | | | | | | | | Income taxes | | | (51 | ) | | 152 | | | (112 | ) | | (11 | ) | | Income before discontinued operations | | | (84 | ) | | 226 | | | 63 | | | 205 | | | Discontinued operations | | | - | | | - | | | (18 | ) | | (18 | ) | | Net Income | | $ | (84 | ) | $ | 226 | | $ | 45 | | $ | 187 | |
Regulated Services - First Six Months of 2006 Compared to First Six Months of 2005
Net income decreased $84 million (16.0%) to $440 million in the first six months of 2006 compared to $524 million in the first six months of 2005, primarily due to decreased operating revenues partially offset by lower operating expenses and taxes.
Revenues -
The decrease in total revenues resulted from the following sources:
| | | Six Months Ended June 30, | | | | | | | Increase | | Revenues By Type of Service | | 2006 | | 2005 | | (Decrease) | | | | | (In millions) | | | Distribution services | | $ | 1,848 | | $ | 2,169 | | $ | (321 | ) | | Transmission services | | | 181 | | | 197 | | | (16 | ) | | Internal lease revenues | | | - | | | 158 | | | (158 | ) | | Other | | | 99 | | | 76 | | | 23 | | | Total Revenues | | $ | 2,128 | | $ | 2,600 | | $ | (472 | ) |
Decreases in distribution deliveries by customer class are summarized in the following table:
Electric Distribution Deliveries | | | | | Residential | | | (3.6 | )% | | Commercial | | | (1.6 | )% | | Industrial | | | (1.2 | )% | | Total Distribution Deliveries | | | (2.2 | )% |
The completion of the Ohio Companies' generation transition cost recovery under their respective transition plans and Penn's transition plan in 2005 was the primary reason for lower distribution unit prices, which, in conjunction with lower KWH deliveries, resulted in lower distribution delivery revenues. The decreases in deliveries to customers were primarily due to unseasonably milder weather during the first six months of 2006 as compared to the same period in 2005. The following table summarizes major factors contributing to the $321 million decrease in distribution service revenues in the first six months of 2006:
Sources of Change in Distribution Revenues | | Increase (Decrease) | | | | | (In millions) | | | Changes in customer usage | | $ | (102 | ) | | Ohio shopping incentives | | | 100 | | | Changes in prices: | | | | | | Rate mix and other | | | (319 | ) | | | | | | | | Net Decrease in Distribution Revenues | | $ | (321 | ) |
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.
Expenses-
The decrease in revenues discussed above was partially offset by the following decreases in total expenses:
| · | Other operating expenses were $43 million lower in 2006 due, in part, to the following factors: |
| 1) | The absence in 2006 of expenses for ancillary service refunds to third parties of $13 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 $6 million incurred in 2005; and |
| 3) | A $33 million decrease in employee and contractor costs resulting from lower storm-related expenses, reduced employee benefits and the decreased use of outside contractors for tree trimming, reliability work, legal services and jobbing and contracting. |
| · | Lower depreciation expense of $77 million resulted from the impact of the generation asset transfers; |
| · | Reduced amortization of regulatory assets of $205 million resulted principally from the completion of Ohio generation transition cost recovery and Penn's transition plan in 2005; and |
| · | General taxes decreased by $5 million primarily due to lower property taxes as a result of the generation asset transfers. |
The reduction in the deferral of new regulatory assets resulted from the 2005 JCP&L rate decision and the end of shopping incentive deferrals under the Ohio Companies’ transition plan, partially offset by the distribution cost deferrals under the Ohio Companies’ RCP.
Other Income and Expense -
| · | Higher investment income reflects the impact of the generation asset transfers. Interest income on the affiliated company notes receivable from the power supply management services segment in the first six months of 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 |
| · | Subsidiaries' preferred stock dividends decreased by $3 million in 2006 due to redemption activity in 2005. |
Power Supply Management Services - First Six Months of 2006 Compared to First Six Months of 2005
Net income for this segment was $175 million in the first six months of 2006 compared to a net loss of $51 million in the same period last year. An improvement in the gross generation margin was partially offset by higher depreciation, general taxes and interest expense resulting from the generation asset transfers.
Revenues -
Electric generation sales revenues increased $423 million in the first six months of 2006 compared to the same period in 2005. This increase primarily resulted from a 7.2% increase in retail KWH sales, mostly due to the return of customers as a result of third-party suppliers leaving the Ohio marketplace, and higher unit prices resulting from the RSP and RCP that were effective in 2006. The higher retail sales reduced energy available for sale to the wholesale market. Increased transmission revenues reflected new revenues of approximately $54 million under the MISO transmission rider that began in the first quarter of 2006. These increases were partially offset by a reduction in wholesale sales revenue as a result of both lower KWH sales and lower unit prices.
The increase in reported segment revenues resulted from the following sources:
| | | Six Months Ended June 30, | | | | | | | Increase | | Revenues By Type of Service | | 2006 | | 2005 | | (Decrease) | | | | | (In millions) | | | Electric Generation Sales: | | | | | | | | | Retail | | $ | 2,524 | | $ | 1,969 | | $ | 555 | | | Wholesale | | | 488 | | | 620 | | | (132 | ) | | Total Electric Generation Sales | | | 3,012 | | | 2,589 | | | 423 | | | Transmission | | | 262 | | | 182 | | | 80 | | | Other | | | 23 | | | 22 | | | 1 | | | Total Revenues | | $ | 3,297 | | $ | 2,793 | | $ | 504 | |
The following table summarizes the price and volume factors contributing to changes in sales revenues from retail and wholesale customers:
| | | Increase | | Source of Change in Electric Generation Sales | | (Decrease) | | | | | (In millions) | | | Retail: | | | | | Effect of 7.2% increase in customer usage | | $ | 141 | | Change in prices | | | 414 | | | | | | 555 | | | Wholesale: | | | | | Effect of 11.9% decrease in KWH sales | | | (74 | ) | Change in prices | | | (58 | ) | | | | | (132 | ) | | Net Increase in Electric Generation Sales | | $ | 423 | |
Expenses -
Total operating expenses increased by $59 million. The increase was due to the following factors:
| · | Higher fuel and purchased power costs of $162 million, including increased fuel costs of $73 million - coal costs increased $81 million as a result of increased generation output, higher coal commodity prices and increased transportation costs for western coal. The increased coal costs were partially offset by lower natural gas and emission allowance costs of $16 million. Purchased power costs increased $89 million due to higher prices partially offset by lower volumes. Factors contributing to the higher 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 | | $ | 37 | | Change due to volume consumed | | | 36 | | | | | | 73 | | | Purchased Power: | | | | | Change due to increased unit costs | | | 130 | | Change due to volume purchased | | | (31 | ) | Increase in NUG costs deferred | | | (10 | ) | | | | | 89 | | | | | | | | | Net Increase in Fuel and Purchased Power Costs | | $ | 162 | |
| · | Higher transmission expenses of $42 million related to the transmission revenues discussed above; |
| · | Increased depreciation expenses of $79 million, resulting principally from the generation asset transfers; and |
| · | Higher general taxes of $17 million due to additional property taxes resulting from the generation asset transfers. |
Partially offsetting these higher costs were lower non-fuel operating expenses of $112 million, which reflect the absence in 2006 of generating asset lease rents of $158 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. The $96 million increase in the deferral of new regulatory assets represents PJM/MISO costs incurred that are expected to be recovered from customers through future rates. The deferrals also include the Ohio RCP fuel deferral of $51 million.
Other Income and Expense -
| · | Investment income in the first six months of 2006 was $17 million higher primarily due to nuclear decommissioning trust investments acquired through the generation asset transfers; and | | | | | · | Interest expense increased by $93 million, primarily due to interest on the associated company notes payable from the generation asset transfers. This increase was partially offset by an additional $9 million of capitalized interest. |
Other - First Six Months of 2006 Compared to First Six Months of 2005
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 $45 million increase to FirstEnergy’s net income in the first six months of 20052006 compared to the same period of 2004.2005. The decreaseincrease was primarily reflecteddue to the effectabsence of the newwrite-off of income tax benefits due to the 2005 change in Ohio tax legislation, (discussedthe financing swap gain described in the Other - Second Quarter 2006 Compared to Second Quarter 2005 results analysis section),above and a $3 million increase in other investment income in the first half of 2006. These increases were partially offset by the effectFSG impairment charge and gas commodity trading results reduction and the absence of discontinued operations, which included an after-tax net gainafter - tax gains of $17 million from discontinued operations in 2005 (see Note 6)4). The following table summarizes the sources of income from discontinued operations:
| | | Six Months Ended | | | | | | | June 30, | | Increase | | | | | 2005 | | 2004 | | (Decrease) | | | | | (In millions) | | | Discontinued operations (net of tax) | | | | | | | | | Gain on sale: | | | | | | | | | | | | Natural gas business | | $ | 5 | | $ | - | | $ | 5 | | | FSG and MYR Subsidiaries | | | 12 | | | - | | | 12 | | | Reclassification of operating income | | | 1 | | | 4 | | | (3 | ) | | Total | | $ | 18 | | $ | 4 | | $ | 14 | | | | | | | | | | | | | |
Postretirement Plans
Pension costs were lower in 2005 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 2005, postretirement benefits expense decreased by $17 million in the second quarter of 2005 and $37 million in the first six months of 2005 compared to the corresponding periods of 2004. The following table summarizes the net pension and OPEB expense (excluding amounts capitalized)operations for the second quarter and first six months ended June 30, 2005 and 2004.2005:
| | | Three Months Ended | | | | Six Months Ended | | | | Postretirement | | June 30, | | | June 30, | | | Benefits Expense * | | 2005 | | 2004 | | (Decrease) | | 2005 | | 2004 | | (Decrease) | | | | | (In millions) | | | | | | | | | | | | | | | | | | Pension | | $ | 8 | | $ | 22 | | $ | (14 | ) | $ | 16 | | $ | 42 | | $ | (26 | ) | | OPEB | | | 18 | | | 21 | | | (3 | ) | | 36 | | | 47 | | | (11 | ) | | Total | | $ | 26 | | $ | 43 | | $ | (17 | ) | $ | 52 | | $ | 89 | | $ | (37 | ) | | | | | | | | | | | | | | | | | | | | | | | * 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 | | | 1 | | | Total | | $ | 18 | |
CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy’s cash requirements in 2005 for operating expenses, construction expenditures, scheduled debt maturities During 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
The FirstEnergy'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 $2.0 billion of short-term financing under a revolving credit 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 whothat are also parties to such facility. In the secondFirstEnergy paid cash dividends to common shareholders of $148 million in each quarter of 2005,2006 totaling $296 million for the first six months of 2006. FirstEnergy received $279$148 million of cash dividends from its subsidiaries and paid $135 million in cash dividends to its common shareholders - in the first six monthsquarter of 2005, it2006 and borrowed against the $2.0 billion revolving credit facility for the second quarter dividend payment. In July, FirstEnergy received and paid $416$500 million and $270 million, respectively.from OE as a result of OE’s repurchase of common stock. There are no material restrictions on the payment of cash dividends by FirstEnergy’sFirstEnergy's subsidiaries.
As of June 30, 2005,2006, FirstEnergy had $50$583 million of cash and cash equivalents ($3 million restricted as an indemnity reserve) compared with $53$64 million ($3 million restricted as an indemnity reserve) as of December 31, 2004.2005. Temporary cash investments of $544 million were used principally to redeem $400 million of the outstanding $1 billion of FirstEnergy’s 5.5% notes in July 2006, in advance of their November 15, 2006 maturity date. The remainder was used in July 2006 to redeem $61 million of OE’s preferred stock and reduce short-term borrowings. The major sources for changes in thesecash and cash equivalent 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 byfrom operating activities was $362$551 million and $332 million in the second quarters of 2005 and 2004, respectively, and $931 million and $979$921 million in the first six months of 20052006 and 2004,2005, respectively, summarized as follows:
| | | Three Months Ended | | Six Months Ended | | | Six Months Ended | | | | | June 30, | | June 30, | | | June 30, | | Operating Cash Flows | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | (In millions) | | | | | | | | | | | | | | | Cash earnings * | | $ | 501 | | $ | 377 | | $ | 865 | | $ | 882 | | | $ | 771 | | $ | 827 | | | Working capital and other | | | (139 | ) | | (45 | ) | | 66 | | | 97 | | | | (220 | ) | | 94 | | | Total cash flows from operating activities | | $ | 362 | | $ | 332 | | $ | 931 | | $ | 979 | | | | Net cash provided from operating activities | | | $ | 551 | | $ | 921 | | | | | | | | | | | | | | | | | | | | | * Cash earnings are a non-GAAP measure (see reconciliation below). | | | | * Cash earnings are a Non-GAAP measure (see reconciliation below). | | * Cash earnings are a Non-GAAP measure (see reconciliation below). |
Cash earnings as disclosed in(in the table above,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.
| | | Six Months Ended | | | | | June 30, | | Reconciliation of Cash Earnings | | 2006 | | 2005 | | | | | (In millions) | | | Net income (GAAP) | | $ | 525 | | $ | 338 | | | Non-cash charges (credits): | | | | | | | | | Provision for depreciation | | | 292 | | | 292 | | | Amortization of regulatory assets | | | 421 | | | 617 | | | Deferral of new regulatory assets | | | (226 | ) | | (180 | ) | | Nuclear fuel and lease amortization | | | 30 | | | 38 | | | Deferred purchased power and other costs | | | (239 | ) | | (210 | ) | | Deferred income taxes and investment tax credits | | | 32 | | | 62 | | | Deferred rents and lease market valuation liability | | | (105 | ) | | (101 | ) | | Accrued compensation and retirement benefits | | | 33 | | | 11 | | | Income from discontinued operations | | | - | | | (18 | ) | | Other non-cash expenses | | | 8 | | | (22 | ) | | Cash earnings (Non-GAAP) | | $ | 771 | | $ | 827 | |
| | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In millions) | | | | | | | | | | | | | | Net income (GAAP) | | $ | 178 | | $ | 204 | | $ | 338 | | $ | 378 | | | Non-cash charges (credits): | | | | | | | | | | | | | | | Provision for depreciation | | | 149 | | | 146 | | | 292 | | | 292 | | | Amortization of regulatory assets | | | 307 | | | 271 | | | 617 | | | 581 | | | Deferral of new regulatory assets | | | (120 | ) | | (68 | ) | | (180 | ) | | (113 | ) | | Nuclear fuel and lease amortization | | | 19 | | | 23 | | | 38 | | | 45 | | | Deferred purchased power and other costs | | | (83 | ) | | (61 | ) | | (192 | ) | | (145 | ) | | Deferred income taxes and investment tax credits | | | 76 | | | (100 | ) | | 62 | | | (94 | ) | | Deferred rents and lease market valuation liability | | | (65 | ) | | (64 | ) | | (101 | ) | | (81 | ) | | Income (loss) from discontinued operations | | | 1 | | | (2 | ) | | (18 | ) | | (4 | ) | | Other non-cash expenses | | | 39 | | | 28 | | | 9 | | | 23 | | | Cash earnings (non-GAAP) | | $ | 501 | | $ | 377 | | $ | 865 | | $ | 882 | | | | | | | | | | | | | | | | |
In the second quarter of 2005,Net cash earnings increased $124provided from operating activities decreased by $370 million from the same period last year as described under "RESULTS OF OPERATIONS." Cash earnings duringin the first six months of 2005 decreased by $17 million from the same period of 2004. In the second quarter of 2005, compared with the second quarter 2004, the use of cash for working capital increased by $94 million, principally from changes in receivables, accrued taxes, prepayments and materials and supplies, offset in part by accounts payable and funds received for prepaid electric service under the Ohio Schools Council’s Energy for Education Program. The use of cash for receivables resulted principally from the conversion of the CFC receivable sale to an on-balance sheet transaction, which added $155 million of receivables to the balance sheet as of June 30, 2005. The first six months of 20052006 compared to the first six months of 2004,2005 primarily due to a $314 million decrease from working capital and a $56 million decrease in cash earnings described under "Results of Operations." The decrease from working capital changes provided $31primarily resulted from $242 million less cash, compared to the same period of 2005, due in part to changes in receivables, accrued taxes and prepayments, offset by accounts payable and the funds received under thein 2005 for prepaid electric service (under a three-year Energy for Education Program.Program with the Ohio Schools Council), increased outflows of $144 million for payables primarily caused by higher fuel and purchased power costs, and $77 million of cash collateral returned to suppliers. These decreases were partially offset by an increase in cash provided from the settlement of receivables of $218 million, reflecting increased electric sales revenues.
Cash Flows From Financing Activities
In the second quarter and first six months of 2005,2006, cash provided from financing activities was $616 million compared to cash used for financing activities was $109 million andof $468 million respectively, compared to $573 million and $813 million in the second quarter and first six months of 2004 respectively.2005. The following table summarizes security issuances and redemptions.
| | | Three Months Ended | | Six Months Ended | | | Six Months Ended | | | | | June 30, | | June 30, | | | June 30, | | Securities Issued or Redeemed | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | | | | | (In millions) | | New issues | | | | | | | | | | | | | | | | Pollution control notes | | $ | 245 | | $ | - | | $ | 245 | | $ | 185 | | | $ | 253 | | $ | 245 | | | Secured notes | | | - | | 300 | | - | | 550 | | | | 200 | | | - | | | Unsecured notes | | | - | | | 3 | | | - | | | 150 | | | | 600 | | | - | | | | | $ | 245 | | $ | 303 | | $ | 245 | | $ | 885 | | | $ | 1,053 | | $ | 245 | | | | | | | | | | | | | | | Redemptions | | | | | | | | | | | | | | | | | | | First mortgage bonds | | $ | 177 | | $ | 290 | | $ | 178 | | $ | 382 | | | $ | 1 | | $ | 178 | | | Pollution control notes | | | 247 | | - | | 247 | | | | | | 307 | | | 247 | | | Secured notes | | | 29 | | 31 | | 48 | | 73 | | | | 179 | | | 49 | | | Long-term revolving credit | | | - | | 175 | | 215 | | 310 | | | | - | | | 215 | | | Unsecured notes | | | - | | 225 | | - | | 225 | | | | Preferred stock | | | 42 | | | - | | | 140 | | | - | | | | 30 | | | 140 | | | | | $ | 495 | | $ | 721 | | $ | 828 | | $ | 990 | | | $ | 517 | | $ | 829 | | | | | | | | | | | | | | | | | | | | | | Short-term borrowings, net increase (decrease) | | $ | 246 | | $ | (60 | ) | $ | 386 | | $ | (447 | ) | | | Short-term borrowings, net | | | $ | 371 | | $ | 386 | |
FirstEnergy had approximately $555 million$1.1 billion of short-term indebtedness as of June 30, 20052006 compared to approximately $170$731 million as of December 31, 2004.2005. This increase was due primarily to higher capital expenditures and common dividend payments compared to Net Cash from Operating Activities during the first half of the year. Available bank borrowingsborrowing capability as of June 30, 20052006 included the following:
Borrowing Capability | | FirstEnergy | | OE* | | Penelec | | Total | | | | | (In millions) | | | | | | | | | | | | | | Short-term revolving credit** | | $ | 2,000 | | $ | - | | $ | - | | $ | 2,000 | | | Utilized | | | (41 | ) | | - | | | - | | | (41 | ) | | Letters of credit | | | (140 | ) | | - | | | - | | | (140 | ) | | Net | | | 1,819 | | | - | | | - | | | 1,819 | | | | | | | | | | | | | | | | | | Short-term bank facilities | | | - | | | 14 | | | 75 | | | 89 | | | Utilized | | | - | | | - | | | (75 | ) | | (75 | ) | | Net | | | - | | | 14 | | | - | | | 14 | | | Total unused borrowing capability | | $ | 1,819 | | $ | 14 | | $ | - | | $ | 1,833 | | | | | | | | | | | | | | | | | | * Short-term revolving credit agreement matured on July 1, 2005 and was not renewed. | | | **Credit facility is also available to OE, Penelec and certain other FirstEnergy subsidiaries, as discussed below. | | | | | | | | | | | | | | | | |
Borrowing Capability | | | | | | | (In millions) | | Short-term credit facilities(1) | | $ | 2,120 | | | Accounts receivable financing facilities | | | 550 | | | Utilized | | | (1,096 | ) | | LOCs | | | (123 | ) | | Net | | $ | 1,451 | | | | | | | | (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 June 30, 2005,2006, the Ohio Companies and Penn had the aggregate capability to issue approximately $4.1$1.5 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 $668$735 million and $570$576 million, respectively, as of June 30, 2005.2006. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of June 30, 2005,2006, JCP&L had the capability to issue $597$610 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 $4.3$5 billion of preferred stock (assuming no additional debt was issued) as of June 30, 2005.2006. CEI, Met-Ed and Penelec do not have nosimilar restrictions onand could issue up to the issuancenumber of preferred stock.shares authorized under their respective charters. As a result of OE redeeming all of its outstanding preferred stock on July 7, 2006, the applicable earnings coverage test is inoperative for OE. Accordingly, as of July 7, 2006, Penn, TE and JCP&L could issue a total of $2.6 billion of preferred stock (assuming no additional debt was issued). In the event that OE issues preferred stock in the future, the applicable earnings coverage test will govern the amount of additional preferred stock that OE may issue. As of June 30, 2005,2006, approximately $1 billion of capacity remained unused under an 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 June 30, 2006, OE had approximately $400 million of capacity remaining unused under its existing shelf registration for unsecured debt securities.
FirstEnergy’s FirstEnergy's working capital and short-term borrowing needs are met principally with a $2 billion five-year revolving credit facility that was entered into on June 14, 2005 by FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as borrowers, with a syndicate of banks. The facility replaced FirstEnergy’s $375 million and $1 billion three-year credit agreements, OE’s $125 million three-year credit agreement and OE’s recently-expired $250 million two-year credit agreement.(included in the table above). Borrowings under the facility are available to each borrower separately and will mature on the earlier of 364 days from the date of borrowing andor the June 16, 2010 commitment terminationexpiration date.
The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations.limitations:
| | Revolving | Regulatory and | | Revolving | | Regulatory and | | | | Credit Facility | Other Short-Term | | Credit Facility | | Other Short-Term | | Borrower | Sub-Limit | Debt Limitations1 | | Sub-Limit | | Debt Limitations1 | | | | (In millions) | | | | | | (In millions) | | FirstEnergy | $2,000 | $1,500 | | $ | 2,000 | | $ | 1,500 | | OE | 500 | | | 500 | | | 500 | | Penn | 50 | 49 | | | 50 | | | 44 | | CEI | 250 | 500 | | | 250 | | | 500 | | TE | 250 | 500 | | | 250 | | | 500 | | JCP&L | 425 | 414 | | | 425 | | | 412 | | Met-Ed | 250 | 2502 | | | 250 | | | 300 | | Penelec | 250 | 2502 | | | 250 | | | 300 | | FES | -3 | n/a | | | (2) | | | n/a | | ATSI | -3 | 26 | | | (2) | | | 26 | |
(1) As of June 30, 2005.
(2) Excluding amounts which may be borrowed under the Utility Money Pool.
| | (3)(1)
| As of June 30, 2006. |
| (2) | Borrowing sublimitssub-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- byLC b S&P and Baa3 by Moody’sMoody's or (ii) FirstEnergy has guaranteed the obligations of such borrower under the facility. |
The revolving credit facility, combined with an aggregate $550 million ($249 million unused as of June 30, 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 letters of creditLOCs expiring up to one year from the date of issuance. The stated amount of outstanding letters of creditLOCs 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 $1.96was $1.5 billion as of June 30, 2005.2006.
The revolving credit facility contains financial covenants such thatrequiring each borrower shallto maintain a consolidated debt to total capitalization ratio of no more than 0.65 to 1.00. In addition, unless and until FirstEnergy obtains senior unsecured debt ratings65%, measured at the end of BBB- by S&P or Baa2 by Moody’s, FirstEnergy will maintain a fixed charge ratio of at least 2.00 to 1.00.
each fiscal quarter. As of June 30, 2005,2006, FirstEnergy and it’s subsidiaries’ fixed charge coverageits subsidiaries' debt to total capitalization ratios as(as defined under the revolving credit agreements,facility) were as follows:
| Debt
| | | To Total
| Fixed Charge
| Borrower | Capitalization
| Ratio
| FirstEnergy | 0.55 to 1.00 | 4.5555 | % | OE | 0.39 to 1.00 | 6.6640 | % | Penn | 0.35 to 1.00 | 16.9734 | % | CEI | 0.58 to 1.00 | 3.8249 | % | TE | 0.43 to 1.00 | 3.4828 | % | JCP&L | 0.31 to 1.00 | 4.9429 | % | Met-Ed | 0.38 to 1.00 | 7.0138 | % | Penelec | 0.35 to 1.00 | 5.6336 | % |
The revolving credit facility does not contain any provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in the credit ratings. Pricing is defined in "pricing grids"“pricing grids”, whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.
FirstEnergy’sFirstEnergy'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. 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 second quarterfirst six months of 20052006 was 2.93%approximately 4.86% for both the regulated companies’ money pool and 2.86% for the unregulated companies' money pool.
On May 16, 2005,FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. The following table displays FirstEnergy’s and the Companies' securities ratings as of July 31, 2006. The ratings outlook from S&P affirmed its 'BBB-' corporate crediton all securities is stable. The ratings outlook from Moody's and Fitch on FirstEnergy and its units and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmation and outlook revision reflects the successful restart of the three nuclear units from their respective outages that occurred during the first half of 2005. S&P noted that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projected and its nuclear operations further stabilize.all securities is positive.
Issuer | | Securities | | S&P | | Moody’s | | Fitch | | | | | | | | | | FirstEnergy | | Senior unsecured | | BBB- | | Baa3 | | BBB- | | | | | | | | | | OE | | Senior unsecured | | BBB- | | Baa2 | | 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 |
On July 18, 2005, Moody’s revised its(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 outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.applies.
On January 20, 2006, TE redeemed all 1.2 million of its outstanding shares of Adjustable Rate Series B preferred stock at $25.00 per share, plus accrued dividends to the date of redemption. On April 3, 2006, $106.5 million of pollution control revenue refunding bonds were issued on behalf of NGC ($60 million at 3.07% and $46.5 million at 3.25%). The total principal or par valueproceeds from the 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%). Also, on April 3, 2006, $146.7 million of optional redemptions duringpollution control revenue refunding bonds were issued on behalf of FGCO ($90.1 million at 3.03% and $56.6 million at 3.10%) which were used to redeem the second quarterfollowing 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 2005 totaled $110FirstEnergy'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. On May 12, 2006, JCP&L issued $200 million with one optional redemption completed following the endof 6.40% secured senior notes due 2036. The proceeds of the second quarter as shownoffering were used to repay at maturity $150 million aggregate principal amount of JCP&L’s 6.45% senior notes due May 15, 2006 and for general corporate purposes. On June 8, 2006, the NJBPU approved JCP&L's request to issue securitization bonds associated with BGS stranded cost deferrals. On August 4, 2006, JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, secured pricing on the issuance of $182 million of transition bonds with a weighted average interest rate of 5.5%.
On June 20, 2006, FirstEnergy's Board of Directors authorized a share repurchase program for up to 12 million shares of common stock. At management’s discretion shares may be acquired on the open market or through privately negotiated transactions, subject to market conditions and other factors. The Board’s authorization of the repurchase program does not require FirstEnergy to purchase any shares and the program may be terminated at any time. The 12 million shares represent 3.6% of the common stock currently outstanding. On June 26, 2006, OE issued $600 million of unsecured senior notes, comprised of $250 million of 6.4% notes due 2016 and $350 million of 6.875% notes due 2036. The majority of the proceeds from this offering were used in July 2006 to repurchase $500 million of OE common stock from FirstEnergy, enabling FirstEnergy to accelerate repayment of $400 million of senior notes that were due to mature in November 2006. The remainder of the table below.
Optional Debt and Preferred Stock Redemptions by Company | | Date of Redemption | | Principal/Par | | Annual Cost | | | | | | (In millions) | | | | | CEI | | | May 1, 2005 | | $ | 2 | | | 7.000 | % | | | | | June 1, 2005 | | | 4 | | | 7.350 | % | | JCP&L | | | May 1, 2005 | | | 6 | | | 7.125 | % | | | | | June 30, 2005 | | | 50 | | | 8.450 | % | | Met-Ed | | | May 1, 2005 | | | 7 | | | 6.000 | % | | Penelec | | | May 1, 2005 | | | 3 | | | 6.125 | % | | Penn | | | May 16, 2005 | | | 13 | | | 7.625 | % | | | | | May 16, 2005 | | | 25 | | | 7.750 | % | | | | | | | $ | 110 | | | | | | | | | | | | | | | | | | TE | | | July 1, 2005 | | $ | 30 | | | 7.000 | % | | | | | | | | | | | | |
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 transmission and distribution of electricity. Capital expenditures by the power supply management services segment are principally generation-related. The following table summarizes the investment activitiesinvestments for the three months and six months ended June 30, 2006 and 2005 and 2004 by FirstEnergy’s regulated services, power supply management services and other segments:segment:
Summary of Cash Flows | | Property | | | | | | | | Used for Investing Activities | | Additions | | Investments | | Other | | Total | | Sources (Uses) | | (In millions) | | | | | | | | | | | | | Six Months Ended June 30, 2006 | | | | | | | | | | | Regulated services | | $ | (356 | ) | $ | 66 | | $ | (9 | ) | $ | (299 | ) | | Power supply management services | | | (347 | ) | | (24 | ) | | 1 | | | (370 | ) | | Other | | | (2 | ) | | 1 | | | (5 | ) | | (6 | ) | | Reconciling items | | | (20 | ) | | 37 | | | 10 | | | 27 | | | Total | | $ | (725 | ) | $ | 80 | | $ | (3 | ) | $ | (648 | ) | | | | | | | | | | | | | | | | Six Months Ended June 30, 2005 | | | | | | | | | | | | | | | Regulated services | | $ | (299 | ) | $ | 9 | | $ | (7 | ) | $ | (297 | ) | | Power supply management services | | | (147 | ) | | 14 | | | (5 | ) | | (138 | ) | | Other | | | (5 | ) | | 4 | | | (19 | ) | | (20 | ) | | Reconciling items | | | (11 | ) | | 10 | | | - | | | (1 | ) | | Total | | $ | (462 | ) | $ | 37 | | $ | (31 | ) | $ | (456 | ) |
Summary of Cash Flows | | Property | | | | | | | | Used for Investing Activities | | Additions | | Investments | | Other | | Total | | Sources (Uses) | | (In millions) | | | | | | | | | | | | | Three Months Ended June 30, 2005 | | | | | | | | | | | Regulated services | | $ | (158 | ) | $ | (19 | ) | $ | (10 | ) | $ | (187 | ) | | Power supply management services | | | (66 | ) | | - | | | - | | | (66 | ) | | Other | | | (2 | ) | | 3 | | | (6 | ) | | (5 | ) | | Reconciling items | | | (7 | ) | | (20 | ) | | - | | | (27 | ) | | Total | | $ | (233 | ) | $ | (36 | ) | $ | (16 | ) | $ | (285 | ) | | | | | | | | | | | | | | | | Three Months Ended June 30, 2004 | | | | | | | | | | | | | | | Regulated services | | $ | (129 | ) | $ | 3 | | $ | (5 | ) | $ | (131 | ) | | Power supply management services | | | (59 | ) | | (2 | ) | | - | | | (61 | ) | | Other | | | (1 | ) | | 180 | | | 2 | | | 181 | | | Reconciling items | | | (8 | ) | | 80 | | | - | | | 72 | | | Total | | $ | (197 | ) | $ | 261 | | $ | (3 | ) | $ | 61 | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Six Months Ended June 30, 2005 | | | | | | | | | | | Regulated services | | $ | (299 | ) | $ | 4 | | $ | (7 | ) | $ | (302 | ) | | Power supply management services | | | (147 | ) | | (1 | ) | | - | | | (148 | ) | | Other | | | (5 | ) | | 19 | | | (19 | ) | | (5 | ) | | Reconciling items | | | (11 | ) | | - | | | - | | | (11 | ) | | Total | | $ | (462 | ) | $ | 22 | | $ | (26 | ) | $ | (466 | ) | | | | | | | | | | | | | | | | Six Months Ended June 30, 2004 | | | | | | | | | | | | | | | Regulated services | | $ | (220 | ) | $ | (46 | ) | $ | (7 | ) | $ | (273 | ) | | Power supply management services | | | (103 | ) | | (3 | ) | | - | | | (106 | ) | | Other | | | (2 | ) | | 173 | | | 4 | | | 175 | | | Reconciling items | | | (10 | ) | | 53 | | | (19 | ) | | 24 | | | Total | | $ | (335 | ) | $ | 177 | | $ | (22 | ) | $ | (180 | ) | | | | | | | | | | | | | | | |
Net cash used for investing activities was $285 million in the second quarter of 2005 compared to $61 million of cash provided from investing activities in the same period of 2004. The change was primarily due to $193 million of lower proceeds from assets sales, a $36 million increase in property additions and an $83 million change in interest rate swap activity. Net cash used for investing activities increased by $286 million in the first six months of 20052006 increased by $192 million compared to the same periodfirst six months of 2004.2005. The increase was principally resulted from lower proceeds from the sale of assets of $150due to a $263 million increasedincrease in property additions which reflects the replacement of $127 millionthe steam generators and a $47 million changereactor head at Beaver Valley Unit 1, air quality control system expenditures and the distribution system Accelerated Reliability Improvement Program. The increase in interest rate swap activity,property additions was partially offset by a $44 million decrease in net nuclear decommissioning trust activities due to the absencecompletion of a $51 million NUG trust refund in 2004.the Ohio Companies' and Penn's transition cost recovery for decommissioning at the end of 2005.
During the secondlast half of 2005,2006, capital requirements for property additions and capital leases are expected to be approximately $622 million, including $24 million for nuclear fuel.$582 million. FirstEnergy hasand the Companies have additional requirements of approximately $41 million$1.2 billion 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.
FirstEnergy’s FirstEnergy's capital spending for the period 2005-20072006-2010 is expected to be about $3.3approximately $6.8 billion (excluding nuclear fuel), of which $1.0$1.2 billion applies to 2005.2006. Investments for additional nuclear fuel during the 2005-2007 period2006-2010 periods are estimated to be approximately $282$745 million, of which approximately $58$164 million applies to 2005.2006. During the same period, FirstEnergy’sFirstEnergy's nuclear fuel investments are expected to be reduced by approximately $284$564 million and $86$91 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 June 30, 2005, the2006, FirstEnergy's maximum exposure to potential future payments under outstanding guarantees and other assurances totaled $2.4approximately $3.5 billion, as summarized below:
| | | Maximum | | Guarantees and Other Assurances | | Exposure | | | | | (In millions) | | | FirstEnergy guarantees of subsidiaries: | | | | Energy and energy-related contracts (1) | | $ | 897 | | Other (2) | | | 172 | | | | | | 1,069 | | | | | | | | | Surety bonds | | | 296 | | Letters of credit (3)(4) | | | 1,058 | | | | | | | | | Total Guarantees and Other Assurances | | $ | 2,423 | | | | | | | | (1)Issued for a one-year term, with a 10-day termination right by FirstEnergy. | | (2)Issued for various terms. | | | | | (3)Includes $140 million issued for various terms under LOC capacity available | | | under FirstEnergy's revolving credit agreement and $299 million outstanding in | | | support of pollution control revenue bonds issued with various maturities. | | (4)Includes approximately $194 million pledged in connection with the sale and | | | leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in connection | | with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged | | in connection with the sale and leaseback of Perry Unit 1 by OE. |
| | | Maximum | | Guarantees and Other Assurances | | Exposure | | | | | (In millions) | | | FirstEnergy Guarantees of Subsidiaries: | | | | Energy and Energy-Related Contracts(1) | | $ | 814 | | Other(2) | | | 1,081 | | | | | | 1,895 | | | | | | | | | Surety Bonds | | | 146 | | LOC(3)(4) | | | 1,471 | | | | | | | | | Total Guarantees and Other Assurances | | $ | 3,512 | |
| (1) | Issued for open-ended terms, with a 10-day termination right by FirstEnergy. |
| (2) | Issued for various terms. |
| (3) | Includes $122 million issued for various terms under LOC capacity available under FirstEnergy’s revolving credit agreement and $730 million outstanding in support of pollution control revenue bonds issued with various maturities. |
| (4) | Includes approximately $194 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry 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 June 30, 2005:2006, FirstEnergy's maximum exposure under these collateral provisions was $501 million.
| | | | | Total | | Collateral Paid | | Remaining | | Collateral Provisions | | | | Exposure | | Cash | | LOC | | Exposure | | | | | | | (In millions) | | | | | | | | | | | | | | | | Credit rating downgrade | | | | | $ | 367 | | $ | 141 | | $ | 18 | | $ | 208 | | | Adverse event | | | | | | 50 | | | - | | | 7 | | | 43 | | | Total | | | | | $ | 417 | | $ | 141 | | $ | 25 | | $ | 251 | | | | | | | | | | | | | | | | | | | |
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 ($4736 million as of June 30, 2005, which is included in the caption "Other" in the above table of Guarantees and Other Assurances),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 satisfied through the operating lease payments. The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.3$1.2 billion as of June 30, 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. On June 16, 2005, the CFC receivables financing structure was renewed and restructured from an off-balance sheet transaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the balance sheet as short-term debt.
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.FirstEnergy and its subsidiaries.
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 and energy transmission.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 derivativesDerivatives 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 the SFAS 133 exemption and are therefore excluded from the table below. Of those contractsContracts that are not exempt from such treatment most areinclude certain 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.above-market costs. On April 1, 2006, FirstEnergy elected to apply the normal purchase and normal sale exception to certain NUG power purchase agreements with a fair value of $13 million (included in “Other” in the table below) in accordance with guidance in DIG C20. The change in the fair value of commodity derivative contracts related to energy production during the second quarterthree months and first six months of 2005ended June 30, 2006 is summarized in the following table:
| | | | | Three Months Ended | | Six Months Ended | | Increase (Decrease) in the Fair Value | | | | June 30, 2005 | | June 30, 2005 | | of Commodity Derivative Contracts | | | | Non-Hedge | | Hedge | | Total | | Non-Hedge | | Hedge | | Total | | | | | | | (In millions) | | Change in the Fair Value of | | | | | | | | | | | | | | | | Commodity Derivative Contracts: | | | | | | | | | | | | | | | | | Outstanding net asset at beginning of period | | | | | $ | 55 | | $ | 3 | | $ | 58 | | $ | 62 | | $ | 2 | | $ | 64 | | | New contract when entered | | | | | | - | | | - | | | - | | | - | | | - | | | - | | | Additions/change in value of existing contracts | | | | | | - | | | (4 | ) | | (4 | ) | | (1 | ) | | 2 | | | 1 | | | Change in techniques/assumptions | | | | | | - | | | - | | | - | | | - | | | - | | | - | | | Settled contracts | | | | | | - | | | (1 | ) | | (1 | ) | | (7 | ) | | - | | | (7 | ) | | Sale of retail natural gas contracts | | | | | | - | | | - | | | - | | | 1 | | | (6 | ) | | (5 | ) | Outstanding net asset at end of period (1) | | | | | $ | 55 | | $ | (2 | ) | $ | 53 | | $ | 55 | | $ | (2 | ) | $ | 53 | | | | | | | | | | | | | | | | | | | | | | | | | | Non-commodity Net Assets at End of Period: | | | | | | | | | | | | | | | | | | | | | | | Interest rate swaps (2) | | | | | | - | | | 12 | | | 12 | | | - | | | 12 | | | 12 | | Net Assets - Derivative Contracts at End of Period | | | | | $ | 55 | | $ | 10 | | $ | 65 | | $ | 55 | | $ | 10 | | $ | 65 | | | | | | | | | | | | | | | | | | | | | | | | | | Impact of Changes in Commodity Derivative Contracts(3) | | | | | | | | | | | | | | | | | | | | | | | | Income Statement effects (pre-tax) | | | | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | | Balance Sheet effects: | | | | | | | | | | | | | | | | | | | | | | | | Other comprehensive income (pre-tax) | | | | | $ | - | | $ | (5 | ) | $ | (5 | ) | $ | - | | $ | (4 | ) | $ | (4 | ) | | Regulatory liability | | | | | $ | - | | $ | - | | $ | - | | $ | (7 | ) | $ | - | | $ | (7 | ) | | | | | | | | | | | | | | | | | | | | | | | | | (1) Includes $54 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. | | | (2) Interest rate swaps are treated as cash flow or fair value hedges. (See Interest Rate Swap Agreements - Fair Value Hedges and Forward | | | Starting Swap Agreements - Cash Flow Hedges) | | | | | (3) Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions. | |
| | Three Months Ended | | Six Months Ended | | Increase (Decrease) in the Fair Value | June 30, 2006 | | June 30, 2006 | | of Commodity Derivative Contracts | Non-Hedge | | Hedge | | Total | | Non-Hedge | | Hedge | | Total | | | | (In millions) | | Change in the Fair Value of | | | | | | | | | | | | | Commodity Derivative Contracts: | | | | | | | | | | | | | | Outstanding net liability at beginning of period | $ | (1,129 | ) | $ | (5 | ) | $ | (1,134 | ) | $ | (1,170 | ) | $ | (3 | ) | $ | (1,173 | ) | | New contract value when entered | | - | | | - | | | - | | | - | | | - | | | - | | | Additions/change in value of existing contracts | | (17 | ) | | (3 | ) | | (20 | ) | | (30 | ) | | (10 | ) | | (40 | ) | | Change in techniques/assumptions | | - | | | - | | | - | | | - | | | - | | | - | | | Settled contracts | | 78 | | | 4 | | | 82 | | | 132 | | | 9 | | | 141 | | | Other | | (13 | ) | | - | | | (13 | ) | | (13 | ) | | - | | | (13 | ) | Outstanding net liability at end of period(1) | | (1,081 | ) | | (4 | ) | | (1,085 | ) | | (1,081 | ) | | (4 | ) | | (1,085 | ) | | | | | | | | | | | | | | | | | | | | | Non-commodity Net Liabilities at End of Period: | | | | | | | | | | | | | | | | | | | Interest Rate Swaps(2) | | - | | | (25 | ) | | (25 | ) | | - | | | (25 | ) | | (25 | ) | Net Liabilities - Derivative Contracts at End of Period | $ | (1,081 | ) | $ | (29 | ) | $ | (1,110 | ) | $ | (1,081 | ) | $ | (29 | ) | $ | (1,110 | ) | | | | | | | | | | | | | | | | | | | | | Impact of Changes in Commodity Derivative Contracts(3) | | | | | | | | | | | | | | | | | | | | Income Statement effects (pre-tax) | $ | (1 | ) | $ | - | | $ | (1 | ) | $ | (3 | ) | $ | - | | $ | (3 | ) | | Balance Sheet effects: | | | | | | | | | | | | | | | | | | | | Other comprehensive income (pre-tax) | $ | - | | $ | 1 | | $ | 1 | | $ | - | | $ | (1 | ) | $ | (1 | ) | | Regulatory assets (net) | $ | (62 | ) | $ | - | | $ | (62 | ) | $ | (105 | ) | $ | - | | $ | (105 | ) |
(1)Includes $1,078 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.
(2)Interest rate swaps are treated as cash flow or fair value hedges (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 June 30, 20052006 as follows:
Balance Sheet Classification | | Non-Hedge | | Hedge | | Total | | | Non-Hedge | | Hedge | | Total | | | | | (In millions) | | | (In millions) | | Current - | | | | | | | | | Current- | | | | | | | | | | Other assets | | $ | 1 | | $ | 2 | | $ | 3 | | | $ | 1 | | $ | 1 | | $ | 2 | | | Other liabilities | | | (1 | ) | | (4 | ) | | (5 | ) | | | (6 | ) | | (4 | ) | | (10 | ) | | | | | | | | | | | | | | | | | | | | | Non-Current - | | | | | | | | | | Non-Current- | | | | | | | | | | | | | Other deferred charges | | | 55 | | 24 | | 79 | | | | 47 | | | 29 | | | 76 | | | Other non-current liabilities | | | - | | | (12 | ) | | (12 | ) | | | Other noncurrent liabilities | | | | (1,123 | ) | | (55 | ) | | (1,178 | ) | | | | | | | | | | | | | | | | | | | | | | Net assets | | $ | 55 | | $ | 10 | | $ | 65 | | | | | | | | | | | | | | | Net liabilities | | | $ | (1,081 | ) | $ | (29 | ) | $ | (1,110 | ) |
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 as of June 30, 2006 are summarized by year are summarized in the following table:
Source of Information | | | | | | | | | | | | | | | | - Fair Value by Contract Year | | 2006(1) | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter | | Total | | | | | (In millions) | | Prices actively quoted(2) | | $ | (1 | ) | $ | (1 | ) | $ | - | | $ | - | | $ | - | | $ | - | | $ | (2 | ) | Other external sources(3) | | | (144 | ) | | (251 | ) | | (220 | ) | | - | | | - | | | - | | | (615 | ) | | Prices based on models | | | - | | | - | | | - | | | (161 | ) | | (138 | ) | | (169 | ) | | (468 | ) | Total(4) | | $ | (145 | ) | $ | (252 | ) | $ | (220 | ) | $ | (161 | ) | $ | (138 | ) | $ | (169 | ) | $ | (1,085 | ) |
Sources of Information - | | | | | | | | | | | | | | | | Fair Value by Contract Year | | 2005 (1) | | 2006 | | 2007 | | 2008 | | 2009 | | Thereafter | | Total | | | | | (In millions) | | | | | | | | | | | | | | | | | | | Prices actively quoted (2) | | $ | 1 | | $ | 1 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | 2 | | Other external sources (3) | | | 9 | | | 8 | | | 10 | | | - | | | - | | | - | | | 27 | | | Prices based on models | | | - | | | - | | | - | | | 8 | | | 8 | | | 8 | | | 24 | | Total (4) | | $ | 10 | | $ | 9 | | $ | 10 | | $ | 8 | | $ | 8 | | $ | 8 | | $ | 53 | | | | | | | | | | | | | | | | | | | | | | | | | | (1) For the last two quarters of 2005. | | | | | | | | | | | | | | | | | | | | | | | (2) Exchange traded. | | | | | | | | | | | | | | | | | | | | | | | (3) Broker quote sheets. | | | | | | | | | | | | | | | | | | | | | | | (4) Includes $54 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. | | | |
(2)Exchange traded. (3)Broker quote sheets. | (4) | Includes $1,078 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 June 30, 2005.2006. Based on derivative contracts held as of June 30, 2005,2006, an adverse 10% change in commodity prices would decrease net income by approximately $2$1 million forduring the next twelve12 months.
Interest Rate Swap Agreements - 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 - protectingdesigned to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lowerwhen interest rates.rates decrease. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. During the second quarterfirst six months of 2005,2006, FirstEnergy executed no new fixed-for-floating interest rate swaps and unwound swaps with a total notional amount of $350 million, (see Note 7).for which FirstEnergy paid $1 million in cash. The loss will be recognized over the remaining maturity of each respective hedged security as increased interest expense. As of June 30, 2005,2006, the debt underlying the $1.4 billion$750 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.54%5.74%, which the swaps have effectively converted to a current weighted average variable interest rate of 4.43%6.68%.
| | | June 30, 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 | | | (2 | ) | | 50 | | | 2010 | | | - | | | | | | - | | | 2011 | | | - | | | 50 | | | 2011 | | | - | | | | | | 300 | | | 2013 | | | (17 | ) | | 450 | | | 2013 | | | (4 | ) | | | | | 150 | | | 2015 | | | (16 | ) | | 150 | | | 2015 | | | (9 | ) | | | | | - | | | 2016 | | | - | | | 150 | | | 2016 | | | - | | | | | | 50 | | | 2025 | | | (4 | ) | | 50 | | | 2025 | | | (1 | ) | | | | | 100 | | | 2031 | | | (11 | ) | | 100 | | | 2031 | | | (5 | ) | | | | $ | 750 | | | | | $ | (54 | ) | $ | 1,100 | | | | | $ | (22 | ) |
| | | June 30, 2005 | | December 31, 2004 | | | | | Notional | | Maturity | | Fair | | Notional | | Maturity | | Fair | | Interest Rate Swaps | | Amount | | Date | | Value | | Amount | | Date | | Value | | | | | (Dollars in millions) | | | | | | | | | | | | | | | | | | Fixed to Floating Rate | | $ | 200 | | | 2006 | | $ | (2 | ) | $ | 200 | | | 2006 | | $ | (1 | ) | | (Fair value hedges) | | | 100 | | | 2008 | | | (1 | ) | | 100 | | | 2008 | | | (1 | ) | | | | | 50 | | | 2010 | | | 1 | | | 100 | | | 2010 | | | 1 | | | | | | 50 | | | 2011 | | | 2 | | | 100 | | | 2011 | | | 2 | | | | | | 450 | | | 2013 | | | 13 | | | 400 | | | 2013 | | | 4 | | | | | | 100 | | | 2014 | | | 4 | | | 100 | | | 2014 | | | 2 | | | | | | 150 | | | 2015 | | | (2 | ) | | 150 | | | 2015 | | | (7 | ) | | | | | 200 | | | 2016 | | | 6 | | | 200 | | | 2016 | | | 1 | | | | | | - | | | 2018 | | | - | | | 150 | | | 2018 | | | 5 | | | | | | - | | | 2019 | | | - | | | 50 | | | 2019 | | | 2 | | | | | | 100 | | | 2031 | | | (2 | ) | | 100 | | | 2031 | | | (4 | ) | | | | $ | 1,400 | | | | | $ | 19 | | $ | 1,650 | | | | | $ | 4 | | | | | | | | | | | | | | | | | | | | | | |
Forward Starting Swap Agreements - Cash Flow Hedges
During the quarter, FirstEnergy entered into severalutilizes forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the planned issuanceanticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated entitiessubsidiaries in the fourth quarter of 2006.2006 through 2008. These derivatives are treated as cash flow hedges, protecting against the risk of changes in the 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 six months of 2006, FirstEnergy revised the tenor and timing of its financing plans, and in the second quarter terminated forward swaps with an aggregate notional value of $600 million concurrent with its subsidiaries issuing long-term debt. FirstEnergy received $41 million in cash related to the termination. The gain associated with the ineffective portion of the terminated hedges ($6 million) was recognized in earnings, with the remainder to be recognized over the terms of the respective forward swaps. As of June 30, 2005,2006, FirstEnergy had entered intooutstanding forward starting swaps with an aggregate notional amount of $375$550 million and an aggregate fair value of $29 million.
| | | June 30, 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 | | $ | - | | | | | | 300 | | | 2016 | | | 14 | | | 600 | | | 2016 | | | 2 | | | | | | 50 | | | 2017 | | | 3 | | | 25 | | | 2017 | | | - | | | | | | 125 | | | 2018 | | | 8 | | | 275 | | | 2018 | | | 1 | | | | | | 50 | | | 2020 | | | 3 | | | 50 | | | 2020 | | | - | | | | | $ | 550 | | | | | $ | 29 | | $ | 975 | | | | | $ | 3 | |
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $976 million and $951 million$1.1 billion as of June 30, 20052006 and December 31, 2004, respectively.2005. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $98$111 million reduction in fair value as of June 30, 2005.2006.
CREDIT RISK Credit risk is the risk of an obligor’s failure to meet the terms of anyan 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 June 30, 2005,2006, the largest credit concentration was with one party currently(currently rated investment grade, thatgrade) represented 8%8.1% of FirstEnergy’sFirstEnergy'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 June 30, 2005.2006.
OutlookOUTLOOK
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 EUOCsCompanies 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. AllRegulatory assets that do not earn a current return totaled approximately $237 million as of June 30, 2006. The following table discloses the regulatory assets are expected to be recovered from customers under the Companies' respective transitionby company 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.by source: | | | | | June 30, | | December 31, | | Increase | | Regulatory Assets* | | | | 2005 | | 2004 | | (Decrease) | | | | | | | (In millions) | | | | | | | | | | | | | OE | | | | | $ | 935 | | $ | 1,116 | | $ | (181 | ) | | CEI | | | | | | 902 | | | 959 | | | (57 | ) | | TE | | | | | | 330 | | | 375 | | | (45 | ) | | JCP&L | | | | | | 2,138 | | | 2,176 | | | (38 | ) | | Met-Ed | | | | | | 673 | | | 693 | | | (20 | ) | | Penelec | | | | | | 183 | | | 200 | | | (17 | ) | | ATSI | | | | | | 17 | | | 13 | | | 4 | | | Total | | | | | $ | 5,178 | | $ | 5,532 | | $ | (354 | ) | | | | | | | | | | | | | | | | | * Penn had net regulatory liabilities of approximately $37 million and $18 million included in Noncurrent | | | Liabilities on the Consolidated Balance Sheet as of June 30, 2005 and December 31, 2004, respectively. | |
| | June 30, | | December 31, | | Increase | | Regulatory Assets* | | 2006 | | 2005 | | (Decrease) | | | | | (In millions) | | | OE | | $ | 756 | | $ | 775 | | $ | (19 | ) | | CEI | | | 859 | | | 862 | | | (3 | ) | | TE | | | 267 | | | 287 | | | (20 | ) | | JCP&L | | | 2,122 | | | 2,227 | | | (105 | ) | | Met-Ed | | | 359 | | | 310 | | | 49 | | | ATSI | | | 33 | | | 25 | | | 8 | | | Total | | $ | 4,396 | | $ | 4,486 | | $ | (90 | ) |
| * | Penn had net regulatory liabilities of approximately $59 million as of June 30, 2006 and December 31, 2005. Penelec had net regulatory liabilities of approximately $135 million and $163 million as of June 30, 2006 and December 31, 2005, respectively. These net regulatory liabilities are included in Other Noncurrent Liabilities on the Consolidated Balance Sheets. |
Regulatory assets by source are as follows:
| | | June 30, | | December 31, | | Increase | | | June 30, | | December 31, | | Increase | | Regulatory Assets by Source | | 2005 | | 2004 | | (Decrease) | | | | | | (In millions) | | Regulatory Assets By Source | | | 2006 | | 2005 | | (Decrease) | | | | | | | | | | | | (In millions) | | | Regulatory transition costs | | $ | 4,380 | | $ | 4,889 | | $ | (509 | ) | | $ | 3,365 | | $ | 3,576 | | $ | (211 | ) | | Customer shopping incentives * | | 736 | | | 612 | | 124 | | | | Customer shopping incentives | | | | 644 | | | 884 | | (240 | ) | | Customer receivables for future income taxes | | 296 | | | 246 | | 50 | | | | 219 | | | 217 | | 2 | | | Societal benefits charge | | 30 | | | 51 | | (21 | ) | | | 19 | | | 29 | | (10 | ) | | Loss on reacquired debt | | 85 | | | 89 | | (4 | ) | | | 40 | | | 41 | | (1 | ) | | Employee postretirement benefit costs | | 60 | | | 65 | | (5 | ) | | | Employee postretirement benefits costs | | | | 51 | | | 55 | | (4 | ) | | Nuclear decommissioning, decontamination | | | | | | | | | | | | | | | | | | | and spent fuel disposal costs | | (166 | ) | | (169 | ) | | 3 | | | | (124 | ) | | (126 | ) | | 2 | | | Asset removal costs | | (361 | ) | | (340 | ) | | (21 | ) | | | (163 | ) | | (365 | ) | | 202 | | | Property losses and unrecovered plant costs | | 40 | | | 50 | | (10 | ) | | | 24 | | | 29 | | (5 | ) | | MISO transmission costs | | 20 | | | - | | 20 | | | | MISO/PJM transmission costs | | | | 135 | | | 91 | | 44 | | | Fuel costs - RCP | | | | 51 | | | - | | 51 | | | Distribution costs - RCP | | | | 81 | | | - | | 81 | | | JCP&L reliability costs | | 27 | | | - | | 27 | | | | 19 | | | 23 | | (4 | ) | | Other | | | | 31 | | | 39 | | | (8 | ) | | | 35 | | | 32 | | | 3 | | | Total | | | $ | 5,178 | | $ | 5,532 | | $ | (354 | ) | | $ | 4,396 | | $ | 4,486 | | $ | (90 | ) | | | | | | | | | | | | | * 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 $736 million as of | | | | June 30, 2005 (OE - $274 million, CEI - $354 million, TE - $108 million) will be recovered through a surcharge | | | | 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. | | | | | | |
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. The 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's 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)an 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 Stipulation that incorporates the final report of a Special Reliability Masteran SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation 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 Orderfinal 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. The SRM completed his work and issued his final report to the NJBPU on June 1, 2006. A meeting was held between JCP&L and the NJBPU on June 29, 2006 to discuss the SRM’s final report. JCP&L filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation. 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. The ERO filing was noticed on April 7, 2006 and comments and reply comments were filed in May, June and July 2006. On July 20, 2006, the FERC certified NERC as the ERO to implement the provisions of Section 215 of the Federal Power Act. The FERC directed NERC to make a compliance filing within ninety days addressing such issues as the regional delegation agreements.
On April 4, 2006, NERC also submitted a filing with the FERC 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. The reliability standards filing was noticed by the FERC on April 18, 2006. In that notice, the FERC announced its intent to issue a Notice of Proposed Rulemaking on the proposed reliability standards at a future date. On May 11, 2006, the FERC staff released a preliminary assessment that cited many deficiencies in the proposed reliability standards. The NERC and industry participants filed comments in response to the Staff’s preliminary assessment. The FERC held a technical conference on the proposed reliability standards on July 6, 2006. The chairman has indicated that the FERC intends to act on the proposed reliability standards by issuing a NOPR in September of this year. Interested parties will be given the opportunity to comment on the NOPR. NERC has requested an effective date of January 1, 2007 for the proposed 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. On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security standards that replaced interim standards put in place in the wake of the September 11, 2001 terrorist attacks, and thirteen additional reliability standards. The security standards became effective on June 1, 2006, and the remaining standards will become effective throughout 2006 and 2007. NERC intends to file the standards with the FERC and relevant Canadian authorities for approval.
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 1411 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 their 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' Rate Stabilization Plan extends currentRSP was intended to establish generation prices through 2008, ensuring adequate generationservice rates beginning January 1, 2006, in response to the PUCO’s concerns about price and supply at stabilized prices, and continuesuncertainty following the end of the Ohio Companies' support of energy efficiency and economictransition plan market development efforts. Onperiod. In 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 the proceeding as well as the associated entries on rehearing. Other key componentsOn September 28, 2005, the Supreme Court of Ohio heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order with respect to the approval of the Rate Stabilization Plan includerate stabilization charge, approval of the following:shopping credits, the granting of interest on shopping credit incentive deferral amounts, and approval of the Ohio Companies’ financial separation plan. It remanded one matter back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient means for customer participation in the competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion for Reconsideration with the Supreme Court of Ohio which was denied by the Court on June 21, 2006. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation, requesting the PUCO to initiate a proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. Separately, the OCC and NOAC also submitted to the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket to address the Court’s concern. The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. 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. |
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 | | $ | 177 | | $ | 95 | | $ | 86 | | $ | 358 | | | 2007 | | | 180 | | | 113 | | | 90 | | | 383 | | | 2008 | | | 208 | | | 130 | | | 111 | | | 449 | | | 2009 | | | - | | | 211 | | | - | | | 211 | | | 2010 | | | - | | | 266 | | | - | | | 266 | | Total Amortization | | $ | 565 | | $ | 815 | | $ | 287 | | $ | 1,667 | |
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. 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:
| | · | Amortization period for transition costs being recovered through the RTC extends for OE to as late as 2007; CEI to as late as mid-2009Recognize fuel and TE to as late as mid-2008;distribution deferrals commencing January 1, 2006; |
| | | | | · | Deferral of interest costsRecognize distribution deferrals on a monthly basis prior to review by the accumulated customer shopping incentives as new regulatory assets; andPUCO Staff; |
| | | | | · | AbilityClarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and | | | | | · | Clarify that distribution expenditures do not have to request increasesbe “accelerated” in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.order to be deferred. |
On May 27, 2005, The PUCO approved the Ohio Companies filed an application withCompanies’ 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 establish a generation rate adjustment rider undersimply accepting the Rate Stabilization Plan. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable toamounts contained in the Ohio Companies' retail customers through a tariff rider to be implementedCompanies’ Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 1, 2006. The application reflects projected increases in fuel costs in4, 2006 compared to 2002 baseline costs. The new rider is seeking to recover all costs above the baseline (approximately $93 million in 2006). Various parties including the OCC have intervened in this case.Order. The Ohio Companies have received discovery requests fromresponded to the OCC and the PUCO staff. A procedural schedule has been establishedapplications 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 notices of appeal with a hearing scheduled for October 4, 2005.
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 Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may require theSupreme Court of Ohio Companies to undertake, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approvedalleging various errors made by the PUCO forin its order approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO and the Ohio Companies in 2004. 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.
See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.
New Jersey
Companies. The 2003 NJBPU decisionAppellees’ Merit Briefs are due on JCP&L's base electric rate proceeding ordered a Phase II proceeding in which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards and determine whether the expenditures and projects undertaken by JCP&L to increase its system's reliability are prudent and reasonable for rate recovery. DependingAugust 4, 2006. Appellants’ Reply Briefs will then be due on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an interim motion and a supplemental and amended motion for rehearing and reconsideration of the 2003 NJBPU decision, respectively. 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 requested an increase to the MTC deferred balance recovery of approximately $20 million annually.24, 2006.
On May 25, 2005, the NJBPU approved two stipulated settlement agreements. The first stipulation between JCP&L and the NJBPU staff resolves all of the issues associated with JCP&L's motion for reconsideration of the 2003 NJBPU order (Phase I Order). The second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase II proceeding. The stipulated settlements provide for, among other things, the following:
·An annual increase in distribution revenues of $23 million effective June 1, 2005, associated with the Phase I Order reconsideration;
·An annual increase in distribution revenues of $36 million effective June 1, 2005, related to JCP&L's Phase II Petition;
·An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its deferred cost balance;
·An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and
·A commitment by JCP&L to maintain a target level of customer service reliability with a reduction in JCP&L's authorized return on common equity to its previous level of 9.5% after the target is not met for two consecutive quarters. The authorized return on common equity would then be restored to 9.75% when the target is met for two consecutive quarters.
The Phase II stipulation included an agreement that the distribution revenues increase reflects a three-year amortization of JCP&L's service reliability improvement costs incurred in 2003-2005. This resulted in the creation of a regulatory asset associated with the accelerated tree trimming costs which were expensed in 2003 and 2004. The establishment of the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million ($0.05 per share of FirstEnergy common stock) in the second quarter of 2005.
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 NJBPU order. New BGS tariffs reflecting the results of a February 2005 auction for the BGS supply became effective June 1, 2005. On May 5, 2005, the NJBPU issued an order that BGS procurement proposals for post transition year four be filed by July 1, 2005. The NJBPU requested that the filings address transmission rate issues and rate design alternatives. JCP&L filed its proposal on July 1, 2005. The auction is scheduled to take place in February 2006 for the supply period beginning June 1, 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 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.
Pennsylvania
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. Met-Ed’s and Penelec’s combined portion of total merger savings is estimated to be approximately $31.5 million. On April 13, 2005, the Commonwealth Court issued an interim order in the remand proceeding that the parties should report the status of the negotiations to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals in May and June 2005 and continue to have settlement discussions.
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 defer differences between NUG contract costs and current market prices.
On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $8 million per month.
See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania.
Transmission
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 original decision, CEI would have been responsible for a portion of new energy market charges imposed by MISO when its energy markets began 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, which became effective April 1, 2005. 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.
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 seekssought recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $30 million per year; however, the Ohio Companies anticipate that this amount will increase. The Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted thereafter each July 1.1 thereafter. The Ohio Companiesparties reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, whichagreement that was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by the Ohio Companies, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. If the settlement stipulation is approved by the PUCO the actual amounts to beon August 31, 2005. The incremental transmission and ancillary service revenues recovered through thefrom January 1 through June 30, 2006 rider will be submittedwere approximately $61 million. That amount included the recovery of a portion of the 2005 deferred MISO expenses as described below. On May 1, 2006, the Ohio Companies filed a modification to the PUCO on or before November 1, 2005.rider to determine revenues ($141 million) from July 2006 through June 2007. The second application seekssought 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 defer incremental transmission and ancillary service-related charges incurred as a participant in the MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Deferral of allPermission to defer costs incurred prior to December 31,30, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. An application filed withOn August 31, 2005, the PUCO to recover theseOCC appealed the PUCO's decision. On January 20, 2006, the OCC sought rehearing of the PUCO’s approval of the recovery of deferred charges over a five-year periodcosts through the rider beginning in 2006, is pending. The OCC, OPAE and the Ohio Companies each filed applications for rehearing. The Ohio Companies sought authority to defer the transmission and ancillary service related costs incurred during the period OctoberJanuary 1, 20032006 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, theJune 30, 2006. The PUCO denied the Ohio Companies and OCC’s applications and, at the request of the Ohio Companies, struck as untimely OPAE’s application. The Ohio Companies andOCC's application on February 6, 2006. On March 23, 2006, the OCC have sixty days from that dateappealed the PUCO's order to file a notice of appeal with the Ohio Supreme Court. 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 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 were heard on May 10, 2006. The Ohio Companies are unable to predict when a decision may be issued.
See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.
Pennsylvania As of June 30, 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 were $335 million and $57 million, respectively. Penelec's $57 million is subject to the pending resolution of taxable income issues associated with NUG trust fund proceeds. The PPUC is reviewing a January 2006 change in Met-Ed’s and Penelec’s NUG purchase power stranded cost accounting methodology. If the PPUC orders Met-Ed and Penelec to reverse the change in accounting methodology, this would result in a pre-tax loss of $10.3 million for Met-Ed.
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 all intervened in the case. 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 have deferred approximately $46 million and $12 million, respectively, representing transmission costs that were incurred from January 1, 2006 through June 30, 2006. On June 5, 2006, the OCA filed before the Commonwealth Court a petition for review of the PPUC's approval of the deferral. On July 12, 2006 the Commonwealth Court granted the PPUC’s motion to quash the OCA’s appeal. The ratemaking treatment of the deferrals will be determined in the comprehensive rate filing proceeding discussed further below. 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 an agent for Met-Ed or Penelec in procuring the services under 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 CBP 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 of $37 million annually and an increase in distribution rates for Penelec of $20 million annually. The PPUC suspended the effective date (June 10, 2006) of the rate changes for seven months after the filing as permitted under Pennsylvania law.
If the PPUC adopts the overall positions taken in the intervenors’ testimony as filed, this would have a material adverse effect on the financial statements of FirstEnergy, Met-Ed and Penelec. Hearings are scheduled for late August 2006 and a PPUC decision is expected early in the first quarter of 2007.
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 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. To the extent that an affiliate of Penn supplies a portion of the PLR load included in the RFP, authorization to make the affiliate sale must be obtained from the FERC. Hearings before the PPUC 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. On April 20, 2006, the PPUC approved the Recommended Decision with additional modifications to use an RFP process to obtain Penn's power supply requirements after 2006 through two separate solicitations. An initial solicitation was held for Penn in May 2006 with all tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results for the first solicitation. On July 18, 2006, the second PLR solicitation was held for Penn. The tranches for the Residential Group and Small Commercial Group were fully subscribed. However, supply was only acquired for three of the five tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved the submissions for the second bid. A residual solicitation is scheduled to be held on August 15, 2006 for the two remaining Large Commercial Group tranches. Acceptance of the winning bids is subject to approval by the PPUC.
On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of April 28, 2006 and May 4, 2006, which together decided the issues associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the Commonwealth Court to review the PPUC’s decision to deny its recovery of certain PLR costs via a reconciliation mechanism and its decision to impose a geographic limitation on the sources of alternative energy credits. On June 7, 2006, the PaDEP filed a Petition for Review appealing the PPUC’s ruling on the method by which alternative energy credits may be acquired and traded. Penn is unable to predict the outcome of this appeal.
See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania.
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 NUGC rates and market sales of NUG energy and capacity. As of June 30, 2006, the accumulated deferred cost balance totaled approximately $638 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 June 8, 2006, the NJBPU approved JCP&L’s request to issue securitization bonds associated with BGS stranded cost deferrals. On August 4, 2006, JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, secured pricing on the issuance of $182 million of transition bonds with a weighted average interest rate of 5.5%.
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 23, 2006, JCP&L filed updated data reflecting actual amounts through December 31, 2005 of $154 million of cost incurred since July 31, 2003. 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 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 last of the quarterly reliability reports was submitted on June 12, 2006. As of June 30, 2006, 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 repeal of PUHCA pursuant to 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 on 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. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. Comments on the alternative proposal were submitted on June 15, 2006. JCP&L is unable to predict the outcome of this proposal.
See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.
FERC Matters
On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism 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 was held in May 2006. Initial briefs were submitted on June 9, 2006, and reply briefs were filed on June 27, 2006. The FERC has ordered the Presiding Judge to issue an initial decision by August 11, 2006.
On November 1, 2004, ATSI filed with FERC a request to defer approximately $54 million of costs to be incurred from 2004 through 2007 in connection with ATSI’s VMEP, which represents ATSI’s adoption of newly identified industry “best practices” for vegetation management. On March 4, 2005, the FERC approved ATSI’s request to defer the VMEP costs (approximately $33 million deferred as of June 30, 2006). On March 28, 2006, ATSI and MISO filed with the 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 was June 1, 2006. Various parties filed comments responsive to the March 28, 2006 submission. The FERC conditionally approved the filing on May 22, 2006, subject to a compliance filing that ATSI made on June 13, 2006. A request for rehearing of the FERC’s May 22, 2006 Order was filed by a party, which ATSI answered. On July 21, 2006, the FERC issued an order stating that it needs more time to consider the matter. In light of that order, there is no time period by which the FERC must act on the pending rehearing request. On July 14, 2006, the FERC accepted the ATSI’s June 13, 2006 compliance filing. The estimated annual revenues to ATSI from the VMEP cost recovery is $12 million.
On January 24, 2006, ATSI and MISO filed a request with the FERC 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 RTOR. 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, the FERC approved the revenue credit correction without suspension, effective April 1, 2006. One party sought rehearing of the FERC's order. The request for rehearing of this order was denied on June 27, 2006. The FERC accepted MISO’s and ATSI’s revised tariff sheets for filing on June 7, 2006. The estimated annual revenue impact of the correction mechanism is approximately $40 million effective on June 1, 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 referralrefund 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. Hearings in the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate. The ALJ recommended an April 1, 2006 effective date for this change in rate design. If the FERC accepts this recommendation, the transmission rate applicable to many load zones in PJM would increase. FirstEnergy believes that significant additional transmission revenues would have to be recovered from the JCP&L, Met-Ed and Penelec transmission zones within PJM. The Companies, as part of the Responsible Pricing Alliance, intend to submit a brief on exceptions within thirty days of the initial decision. Following submission of reply exceptions, the case is expected to be reviewed by the FERC with a decision anticipated in the fourth quarter of 2006. 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 CBP 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 through two separate solicitations. An initial solicitation was held for Penn in May 2006 with all tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results for the first solicitation. On July 18, 2006, the second PLR solicitation was held for Penn. The tranches for the Residential Group and Small Commercial Group were fully subscribed. However, supply was only acquired for three of the five tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved the submission for the second bid. A residual solicitation is scheduled to be held on August 15, 2006 for the two remaining Large Commercial Group tranches. Acceptance of the winning bids is subject to approval by the PPUC.
On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticized the Ohio CBP, 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. Under the procedural schedule, aproved in this case, FES expected an initial decision to be issued in late January 2007. However, on July 14, 2006, the Chief Judge granted the joint motion of FES and the Trial Staff to appoint a settlement judge in this proceeding. The procedural schedule has been suspended pending negotiations among the parties.
Environmental Matters
The Companies accrueFirstEnergy accrues environmental liabilities only when they concludeit concludes that it is probable that they haveit has an obligation for such costs and can reasonably determineestimate the amount of such costs. Unasserted claims are reflected in the Companies’FirstEnergy’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
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 byOn December 1, 2005, FirstEnergy issued a comprehensive report to shareholders regarding air emissions regulations and will postan assessment of future risks and mitigation efforts. The report is available on FirstEnergy's Web site at www.firstenergycorp.com/environmental.
Clean Air Act Compliance
FirstEnergy is required to meet federally approved SO2 regulations. Violations of such regulations can result in shutdown of the reportgenerating 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. FirstEnergy cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006 alleging violations to various sections of the Clean Air Act. A meeting has been scheduled for August 8, 2006 to discuss the alleged violations with the EPA.
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. NOX reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOX reductions from FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its web site, facilities are also complying with the NOwww.firstenergycorp.comX. 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. OnIn 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 facilitiesfacility 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. OnIn 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. However, 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 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.
Pennsylvania has proposed a new rule to regulate mercury emissions from coal-fired power plants that does not provide a cap and trade approach as in CAMR, but rather follows a command and control approach imposing emission limits on individual sources. If adopted as proposed, Pennsylvania’s mercury regulation would deprive FirstEnergy of mercury emission allowances that were to be allocated to the Mansfield Plant under CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. The future cost of compliance with these regulations, if adopted and implemented as proposed, 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, including 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 in the form of a Consent Decree that was approved by the Court on July 11, 2005, and 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 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 toward environmentally beneficial projects, which include wind energy purchasepurchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties payablepaid by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized 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.
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 June 30, 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 $70 million have been accrued liabilities aggregating approximately $64 million as ofthrough June 30, 2005.2006.
See Note 13(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, 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 websiteWeb site (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. FirstEnergy is also is proceeding with the implementation of the 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 new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that theequipment. The 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 FirstEnergy’s 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.
Three substantially similar actions were filed in various Ohio State courts by plaintiffs seekingFirstEnergy companies also are defending six separate complaint cases before the PUCO relating to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All threeoutage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. Two ofIn these cases were refiled at the PUCO, one in 2004 and another in 2005. In each, individual complainants���complainants—three in one case and four in the other—seek damages related to the outages and also seeksought to represent others as part of a class action. FirstEnergy has filed responsive pleadings to both cases. The PUCO has dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. BothThree other pending PUCO complaint cases are otherwise currently pending further proceedings. In addition to the two cases that were refiled at the PUCO, the Ohio Companies were namedfiled by various insurance carriers either in their own name 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 was filed on August 25, 2004 against FirstEnergysubrogees or in the New York State Supreme Court.name of their insured. In thiseach of these three cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, several plaintiffs in the New York City metropolitan area allege that they sufferedfrom 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 power outages. None of the plaintiffs2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy affiliate.company. The sixth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It is currently expected that this case will be summarily dismissed, although the Motion is still pending. 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 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. 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 that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed an amended complaint and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. These motions are pending. Additionally, on June 23, 2006, one of the insurance carrier complainants filed an appeal with the Ohio Supreme Court on October 22, 2004. No timetableover the PUCO’s denial of their motion for a decisionrehearing on the issue of the admissibility of the Task Force Report and the dismissal of FirstEnergy Corp. as a respondent. Briefing is expected to be completed on this appeal by mid-September. It is unknown when the Supreme Court will rule on the appeal. No estimate of potential liability is available for any of these cases.
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. FirstEnergy's motion to dismiss the matter was denied on June 2, 2006. FirstEnergy has since filed an appeal, which is pending. A responsive pleading to this matter has been established byfiled. Also, the Court. No damage estimatecomplaint has been provided and thusamended to include an additional party. No estimate of potential liability has been undertaken in this matter.
FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy were based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. The plaintiff has not been determined.appealed.
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 had 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 (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. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.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. On July 8, 2005, FENOC requested an additional 120 days to respond to the NOV. FirstEnergy accrued $2.0$2 million for the proposeda potential fine in 2004prior to 2005 and accrued the remaining liability for the proposed fine 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 have legal liability basedresponse to the NRC's NOV on the events surrounding Davis-Besse it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.
Effective July 1, 2005head degradation to reflect the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned todeferred prosecution agreement that FENOC had reached with the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens.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 preceding two years.years and the licensee's failure to take prompt and corrective action. FENOC operates the Perry Nuclear Power Plant, which currently is owned and/or leased by OE, CEI, TE and Penn (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which include owned portions of the plant). 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.
On May 26,September 28, 2005, the NRC heldsent a public meetingCAL to discuss its oversight ofFENOC describing commitments that FENOC had made to improve the performance at the Perry Plant. While the NRCPlant and stated that the plantCAL 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 safely,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 overall performance had not substantially improved sinceof the heightened inspectionfacility was initiated.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.
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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 now repealed 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 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 of a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. Both filings were consolidated for hearing and decision described above. 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. On May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s complaint and approving the related tariffs, thus affirming OE’s entitlement to recovery of its transition charges. The City of Huron filed an application for rehearing of the PUCO’s decision on June 9, 2006 and OE filed a memorandum in opposition to that application on June 19, 2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The City of Huron has 60 days from the denial of rehearing to appeal the PUCO’s decision.
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 13(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
| SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"FSP FIN 46(R)-6 - “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)”
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In May 2005,April 2006, the FASB issued SFAS 154FSP FIN 46(R)-6 that addresses how a reporting enterprise should determine the variability to changebe considered in applying FASB Interpretation No. 46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the requirements for accountingfirst quarter of 2004, consolidating VIE’s when FirstEnergy or one of its subsidiaries is determined to be the VIE’s primary beneficiary. The variability that is considered in applying Interpretation 46(R) affects the determination of (a) whether the entity is a VIE; (b) which interests are variable interests in the entity; and (c) which party, if any, is the primary beneficiary of the VIE. This FSP states that the variability to be considered shall be based on an analysis of the design of the entity, involving two steps:
| Step 1: | Analyze the nature of the risks in the entity | | Step 2: | Determine the purpose(s) for which the entity was created and determine the variability the entity is designed to create and pass along to its interest holders. |
After determining the variability to consider, the reporting a changeenterprise can determine which interests are designed to absorb that variability. The guidance in accounting principle. It appliesthis FSP is applied prospectively to all voluntary changes in accounting principleentities (including newly created entities) with which that enterprise first becomes involved and to changesall entities previously required by an accounting pronouncementto be analyzed under Interpretation 46(R) when that pronouncementa reconsideration event has occurred after July 1, 2006. FirstEnergy does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances,expect this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and thathave a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement ofmaterial impact on its financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. FirstEnergy will adopt this Statement effective January 1, 2006.statements.
FIN 47, "Accounting48 - “Accounting for Conditional Asset Retirement ObligationsUncertainty in Income Taxes - an interpretation of FASB Statement No. 143"109.”
On March 30, 2005,In June 2006, the FASB issued FIN 4748 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to clarify the scopebe taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and timingtransition. The evaluation of liability recognition for conditional asset retirement obligations. Undera tax position in accordance with this interpretation companies are requiredwill be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit 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 second 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.financial statements. This Interpretationinterpretation is effective no later than the end offor fiscal years endingbeginning after December 15, 2005. Therefore, FirstEnergy will adopt this Interpretation in the fourth quarter of 2005.2006. FirstEnergy is currently evaluating the effectimpact of this Interpretation will have on its financial statements.Statement.
SFAS 123(R), "Share-Based Payment"
In December 2004, the FASB issued SFAS 123(R), a 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. Therefore, FirstEnergy will adopt this Statement effective January 1, 2006. 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"SUBSEQUENT EVENTS
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 indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy continues to evaluate its investments as required by existing authoritative guidance.Pennsylvania Law Change
| FSP 109-1, "Application of FASB Statement No. 109, Accounting for Income Taxes, toOn July 12, 2006, the Governor of Pennsylvania signed House Bill 859, which increases 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 nine 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)deduction allowed for the corporate net income tax from $2 million to $3 million, or the greater of 12.5% of taxable income. As a result, FirstEnergy expects to recognize a net operating loss benefit of $2.2 million (net of federal tax benefit) in the third quarter of 2006.
New Jersey Law Change
On July 8, 2006, the Governor of New Jersey signed tax legislation that increased the current New Jersey Corporate Business tax by an additional 4% surtax, which increases the effective tax from 9% to 9.36%. This increase applies to JCP&L’s 2006 through 2008 tax deductionyears and 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 109, "Accounting for Income Taxes." FirstEnergy is currently evaluating this FSP and does not expect itexpected to have a material impact on the Company's financial statements.FirstEnergy’s or JCP&L’s results of operations.
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 | | Six Months Ended | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | 2006 | | 2005 | | | | | (In thousands) | | | STATEMENTS OF INCOME | | | | | | | | | | | (In thousands) | | | | | | | | | | | | | | | | | | | | | | OPERATING REVENUES | | $ | 716,612 | | $ | 718,347 | | $ | 1,442,970 | | $ | 1,461,642 | | | REVENUES | | | $ | 573,092 | | $ | 716,612 | | $ | 1,159,295 | | $ | 1,442,970 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | Fuel | | | 12,006 | | | 13,844 | | | 23,922 | | | 28,914 | | | | 2,821 | | | 12,006 | | | 5,772 | | | 23,922 | | | Purchased power | | | 227,507 | | | 237,826 | | | 474,097 | | | 487,707 | | | | 293,033 | | | 227,507 | | | 576,053 | | | 474,097 | | | Nuclear operating costs | | | 92,607 | | | 74,392 | | | 188,260 | | | 154,033 | | | | 43,506 | | | 92,607 | | | 84,590 | | | 188,260 | | | Other operating costs | | | 95,589 | | | 91,797 | | | 178,768 | | | 177,157 | | | | 91,604 | | | 95,589 | | | 182,414 | | | 178,768 | | | Provision for depreciation | | | 31,654 | | | 30,215 | | | 57,706 | | | 60,144 | | | | 17,547 | | | 31,654 | | | 35,563 | | | 57,706 | | | Amortization of regulatory assets | | | 109,670 | | | 100,124 | | | 221,441 | | | 213,819 | | | | 43,444 | | | 109,670 | | | 97,305 | | | 221,441 | | | Deferral of new regulatory assets | | | (39,026 | ) | | (25,167 | ) | | (63,821 | ) | | (44,062 | ) | | | (42,083 | ) | | (39,026 | ) | | (78,323 | ) | | (63,821 | ) | | General taxes | | | 46,043 | | | 39,488 | | | 94,121 | | | 88,054 | | | | 43,931 | | | 46,043 | | | 89,826 | | | 94,121 | | | Income taxes | | | 91,192 | | | 65,787 | | | 146,164 | | | 127,361 | | | | Total operating expenses and taxes | | | 667,242 | | | 628,306 | | | 1,320,658 | | | 1,293,127 | | | | Total expenses | | | | 493,803 | | | 576,050 | | | 993,200 | | | 1,174,494 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 49,370 | | | 90,041 | | | 122,312 | | | 168,515 | | | | 79,289 | | | 140,562 | | | 166,095 | | | 268,476 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | OTHER INCOME (net of income taxes) | | | 16,860 | | | 16,787 | | | 17,283 | | | 33,144 | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | Investment income | | | | 32,818 | | | 22,482 | | | 65,860 | | | 43,089 | | | Miscellaneous expense | | | | (1,001 | ) | | (2,161 | ) | | (804 | ) | | (23,897 | ) | | Interest expense | | | | (17,366 | ) | | (21,402 | ) | | (35,598 | ) | | (39,605 | ) | | Capitalized interest | | | | 643 | | | 3,006 | | | 1,134 | | | 5,241 | | | Subsidiary's preferred stock dividend requirements | | | | (155 | ) | | (738 | ) | | (311 | ) | | (1,378 | ) | | Total other income (expense) | | | | 14,939 | | | 1,187 | | | 30,281 | | | (16,550 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | | | | | Interest on long-term debt | | | 15,732 | | | 16,395 | | | 31,341 | | | 32,984 | | | | Allowance for borrowed funds used during construction | | | | | | | | | | | | | | | | and capitalized interest | | | (3,006 | ) | | (1,593 | ) | | (5,241 | ) | | (2,974 | ) | | | Other interest expense | | | 5,670 | | | 4,046 | | | 8,264 | | | 6,936 | | | | Subsidiary's preferred stock dividend requirements | | | 738 | | | 640 | | | 1,378 | | | 1,280 | | | | Net interest charges | | | 19,134 | | | 19,488 | | | 35,742 | | | 38,226 | | | INCOME TAXES | | | | 35,019 | | | 94,653 | | | 73,337 | | | 148,073 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | | 47,096 | | | 87,340 | | | 103,853 | | | 163,433 | | | | 59,209 | | | 47,096 | | | 123,039 | | | 103,853 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | 658 | | | 659 | | | 1,317 | | | 1,220 | | | PREFERRED STOCK DIVIDEND REQUIREMENTS AND | | | | | | | | | | | | | | | REDEMPTION PREMIUM | | | | 3,587 | | | 658 | | | 4,246 | | | 1,317 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | EARNINGS ON COMMON STOCK | | $ | 46,438 | | $ | 86,681 | | $ | 102,536 | | $ | 162,213 | | | $ | 55,622 | | $ | 46,438 | | $ | 118,793 | | $ | 102,536 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 47,096 | | $ | 87,340 | | $ | 103,853 | | $ | 163,433 | | | $ | 59,209 | | $ | 47,096 | | $ | 123,039 | | $ | 103,853 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unrealized gain (loss) on available for sale securities | | | (12,960 | ) | | (1,021 | ) | | (15,677 | ) | | 4,146 | | | | (4,063 | ) | | (12,960 | ) | | 1,672 | | | (15,677 | ) | | Income tax (benefit) related to other comprehensive income | | | (4,546 | ) | | (421 | ) | | (5,670 | ) | | 1,709 | | | | Income tax expense (benefit) related to other | | | | | | | | | | | | | | | | comprehensive income | | | | (1,466 | ) | | (4,546 | ) | | 603 | | | (5,670 | ) | | Other comprehensive income (loss), net of tax | | | (8,414 | ) | | (600 | ) | | (10,007 | ) | | 2,437 | | | | (2,597 | ) | | (8,414 | ) | | 1,069 | | | (10,007 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 38,682 | | $ | 86,740 | | $ | 93,846 | | $ | 165,870 | | | $ | 56,612 | | $ | 38,682 | | $ | 124,108 | | $ | 93,846 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these | | | | statements. | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these statements. | | The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these statements. | |
OHIO EDISON COMPANY | OHIO EDISON COMPANY | | OHIO EDISON COMPANY | | | | | | | | | | | CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | (Unaudited) | | (Unaudited) | | | | | June 30, | | December 31, | | | June 30, | | December 31, | | | | | 2005 | | 2004 | | | 2006 | | | 2005 | | | | | (In thousands) | | | (In thousands) | | ASSETS | | | | | | | | | | | | CURRENT ASSETS: | | | | | | | | | Cash and cash equivalents | | | $ | 545,292 | | | | $ | 929 | | | Receivables- | | | | | | | | | | | | Customers (less accumulated provisions of $8,627,000 and $7,619,000, respectively, | | | | | | | | | | | | for uncollectible accounts) | | | | 250,079 | | | | | 290,887 | | | Associated companies | | | | 165,501 | | | | | 187,072 | | | Other (less accumulated provisions of $52,000 and $4,000, respectively, | | | | | | | | | | | | for uncollectible accounts) | | | | 11,491 | | | | | 15,327 | | | Notes receivable from associated companies | | | | 506,337 | | | | | 536,629 | | | Prepayments and other | | | | 22,794 | | | | | 93,129 | | | | | | | 1,501,494 | | | | | 1,123,973 | | UTILITY PLANT: | | | | | | | | | | | | | | | | In service | | $ | 5,553,362 | | $ | 5,440,374 | | | | 2,558,212 | | | | | 2,526,851 | | | Less - Accumulated provision for depreciation | | | 2,770,924 | | | 2,716,851 | | | | 996,261 | | | | | 984,463 | | | | | | 2,782,438 | | | 2,723,523 | | | | 1,561,951 | | | | | 1,542,388 | | | Construction work in progress - | | | | | | | | | | Electric plant | | | 226,124 | | | 203,167 | | | | Nuclear fuel | | | - | | | 21,694 | | | | | | | 226,124 | | | 224,861 | | | | Construction work in progress | | | | 63,277 | | | | | 58,785 | | | | | | 3,008,562 | | | 2,948,384 | | | | 1,625,228 | | | | | 1,601,173 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | | | | | | | Long-term notes receivable from associated companies | | | | 1,676,228 | | | | | 1,758,776 | | | Investment in lease obligation bonds | | | 341,582 | | | 354,707 | | | | 310,285 | | | | | 325,729 | | | Nuclear plant decommissioning trusts | | | 447,649 | | | 436,134 | | | | 106,360 | | | | | 103,854 | | | Long-term notes receivable from associated companies | | | 207,430 | | | 208,170 | | | | Other | | | 45,394 | | | 48,579 | | | | 40,968 | | | | | 44,210 | | | | | | 1,042,055 | | | 1,047,590 | | | | 2,133,841 | | | | | 2,232,569 | | CURRENT ASSETS: | | | | | | | | | | Cash and cash equivalents | | | 1,283 | | | 1,230 | | | | Receivables - | | | | | | | | | | Customers (less accumulated provisions of $6,282,000 and $6,302,000, respectively, | | | | | | | | | | for uncollectible accounts) | | | 282,283 | | | 274,304 | | | | Associated companies | | | 167,260 | | | 245,148 | | | | Other (less accumulated provisions of $52,000 and $64,000, respectively, | | | | | | | | | | for uncollectible accounts) | | | 10,549 | | | 18,385 | | | | Notes receivable from associated companies | | | 598,151 | | | 538,871 | | | | Materials and supplies, at average cost | | | 108,221 | | | 90,072 | | | | Prepayments and other | | | 20,324 | | | 13,104 | | | | | | | 1,188,071 | | | 1,181,114 | | | DEFERRED CHARGES: | | | | | | | | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | Regulatory assets | | | 935,223 | | | 1,115,627 | | | | 756,481 | | | | | 774,983 | | | Prepaid pension costs | | | | 227,815 | | | | | 224,813 | | | Property taxes | | | 61,419 | | | 61,419 | | | | 52,897 | | | | | 52,875 | | | Unamortized sale and leaseback costs | | | 57,670 | | | 60,242 | | | | 52,637 | | | | | 55,139 | | | Other | | | 67,867 | | | 68,275 | | | | 26,988 | | | | | 31,752 | | | | | | 1,122,179 | | | 1,305,563 | | | | 1,116,818 | | | | | 1,139,562 | | | | | $ | 6,360,867 | | $ | 6,482,651 | | | $ | 6,377,381 | | | | $ | 6,097,277 | | CAPITALIZATION AND LIABILITIES | | | | | | | | | CAPITALIZATION: | | | | | | | | | | Common stockholder's equity - | | | | | | | | | | Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding | | $ | 2,099,089 | | $ | 2,098,729 | | | | Accumulated other comprehensive loss | | | (57,125 | ) | | (47,118 | ) | | | Retained earnings | | | 367,734 | | | 442,198 | | | | Total common stockholder's equity | | | 2,409,698 | | | 2,493,809 | | | | Preferred stock | | | 60,965 | | | 60,965 | | | | Preferred stock of consolidated subsidiary | | | 14,105 | | | 39,105 | | | | Long-term debt and other long-term obligations | | | 1,104,584 | | | 1,114,914 | | | | | | | 3,589,352 | | | 3,708,793 | | | LIABILITIES AND CAPITALIZATION | | | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | Currently payable long-term debt | | | 289,215 | | | 398,263 | | | $ | 225,625 | | | | $ | 280,255 | | | Short-term borrowings - | | | | | | | | | | Short-term borrowings- | | | | | | | | | | | | Associated companies | | | 82,389 | | | 11,852 | | | | 2,161 | | | | | 57,715 | | | Other | | | 143,912 | | | 167,007 | | | | 22,431 | | | | | 143,585 | | | Accounts payable - | | | | | | | | | | Accounts payable- | | | | | | | | | | | | Associated companies | | | 100,452 | | | 187,921 | | | | 123,912 | | | | | 172,511 | | | Other | | | 12,824 | | | 10,582 | | | | 12,312 | | | | | 9,607 | | | Accrued taxes | | | 172,478 | | | 153,400 | | | | 173,248 | | | | | 163,870 | | | Accrued interest | | | | 7,150 | | | | | 8,333 | | | Other | | | 84,545 | | | 74,663 | | | | 64,098 | | | | | 61,726 | | | | | | | 630,937 | | | | | 897,602 | | CAPITALIZATION: | | | | | | | | | | | | Common stockholder's equity- | | | | | | | | | | | | Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding | | | | 2,296,525 | | | | | 2,297,253 | | | Accumulated other comprehensive income | | | | 5,163 | | | | | 4,094 | | | Retained earnings | | | | 285,434 | | | | | 200,844 | | | Total common stockholder's equity | | | | 2,587,122 | | | | | 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 | | | | 1,521,863 | | | | | 1,019,642 | | | | | | 885,815 | | | 1,003,688 | | | | 4,184,055 | | | | | 3,596,903 | | NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | Accumulated deferred income taxes | | | 724,040 | | | 766,276 | | | | 747,568 | | | | | 769,031 | | | Accumulated deferred investment tax credits | | | 55,800 | | | 62,471 | | | | 22,307 | | | | | 24,081 | | | Asset retirement obligation | | | 350,387 | | | 339,134 | | | | 85,578 | | | | | 82,527 | | | Retirement benefits | | | 314,543 | | | 307,880 | | | | 294,755 | | | | | 291,051 | | | Deferred revenues - electric service programs | | | | 104,855 | | | | | 121,693 | | | Other | | | 440,930 | | | 294,409 | | | | 307,326 | | | | | 314,389 | | | | | | 1,885,700 | | | 1,770,170 | | | | 1,562,389 | | | | | 1,602,772 | | COMMITMENTS AND CONTINGENCIES (Note 13) | | | | | | | | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | | | | $ | 6,360,867 | | $ | 6,482,651 | | | $ | 6,377,381 | | | | $ | 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. | The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets. | | | | 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) | | | | | | | | | | | | Six Months Ended | | | | | June 30, | | | | | 2006 | | 2005 | | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 123,039 | | $ | 103,853 | | | Adjustments to reconcile net income to net cash from operating activities - | | | | | | | | | Provision for depreciation | | | 35,563 | | | 57,706 | | | Amortization of regulatory assets | | | 97,305 | | | 221,441 | | | Deferral of new regulatory assets | | | (78,323 | ) | | (63,821 | ) | | Nuclear fuel and lease amortization | | | (11,337 | ) | | 18,663 | | | Amortization of lease costs | | | (4,334 | ) | | (2,952 | ) | | Deferred income taxes and investment tax credits, net | | | (17,351 | ) | | (5,142 | ) | | Accrued compensation and retirement benefits | | | 930 | | | 3,504 | | | Decrease (increase) in operating assets - | | | | | | | | | Receivables | | | 66,215 | | | 77,745 | | | Materials and supplies | | | - | | | (18,149 | ) | | Prepayments and other current assets | | | 70,335 | | | (7,220 | ) | | Increase (decrease) in operating liabilities - | | | | | | | | | Accounts payable | | | (45,894 | ) | | (85,227 | ) | | Accrued taxes | | | 9,378 | | | 19,078 | | | Accrued interest | | | (1,183 | ) | | (791 | ) | | Electric service prepayment programs | | | (16,838 | ) | | 132,151 | | | Other | | | (8,772 | ) | | 12,876 | | | Net cash provided from operating activities | | | 218,733 | | | 463,715 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing - | | | | | | | | | Long-term debt | | | 599,778 | | | 146,450 | | | Short-term borrowings, net | | | - | | | 47,442 | | | Redemptions and Repayments - | | | | | | | | | Preferred stock | | | - | | | (37,750 | ) | | Long-term debt | | | (146,893 | ) | | (260,508 | ) | | Short-term borrowings, net | | | (176,708 | ) | | - | | | Dividend Payments - | | | | | | | | | Common stock | | | (35,000 | ) | | (177,000 | ) | | Preferred stock | | | (1,317 | ) | | (1,317 | ) | | Net cash provided from (used for) financing activities | | | 239,860 | | | (282,683 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (49,659 | ) | | (121,458 | ) | | Proceeds from nuclear decommissioning trust fund sales | | | 30,269 | | | 122,374 | | | Investments in nuclear decommissioning trust funds | | | (30,961 | ) | | (138,144 | ) | | Loan repayments from (loans to) associated companies, net | | | 112,840 | | | (58,540 | ) | | Other | | | 23,281 | | | 14,789 | | | Net cash provided from (used for) investing activities | | | 85,770 | | | (180,979 | ) | | | | | | | | | | | Net increase in cash and cash equivalents | | | 544,363 | | | 53 | | | Cash and cash equivalents at beginning of period | | | 929 | | | 1,230 | | | Cash and cash equivalents at end of period | | $ | 545,292 | | $ | 1,283 | | | | | | | | | | | | 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 STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In thousands) | | | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | Net income | | $ | 47,096 | | $ | 87,340 | | $ | 103,853 | | $ | 163,433 | | | Adjustments to reconcile net income to net cash from | | | | | | | | | | | | | | | operating activities - | | | | | | | | | | | | | | | Provision for depreciation | | | 31,654 | | | 30,215 | | | 57,706 | | | 60,144 | | | Amortization of regulatory assets | | | 109,670 | | | 100,124 | | | 221,441 | | | 213,819 | | | Deferral of new regulatory assets | | | (39,026 | ) | | (25,167 | ) | | (63,821 | ) | | (44,062 | ) | | Nuclear fuel and lease amortization | | | 9,493 | | | 10,591 | | | 18,663 | | | 21,852 | | | Amortization of lease costs | | | (35,982 | ) | | (35,482 | ) | | (2,952 | ) | | (2,452 | ) | | Amortization of electric service obligation | | | (3,991 | ) | | - | | | (3,991 | ) | | - | | | Deferred income taxes and investment tax credits, net | | | 19,485 | | | (20,542 | ) | | (5,142 | ) | | (50,587 | ) | | Accrued retirement benefit obligations | | | 4,627 | | | 6,106 | | | 6,661 | | | 17,229 | | | Accrued compensation, net | | | 850 | | | (372 | ) | | (3,157 | ) | | 4,032 | | | Decrease (increase) in operating assets - | | | | | | | | | | | | | | | Receivables | | | (8,378 | ) | | 127,707 | | | 77,745 | | | 75,772 | | | Materials and supplies | | | (2,315 | ) | | (3,104 | ) | | (18,149 | ) | | (5,866 | ) | | Prepayments and other current assets | | | 5,657 | | | 5,315 | | | (7,220 | ) | | (6,514 | ) | | Increase (decrease) in operating liabilities - | | | | | | | | | | | | | | | Accounts payable | | | (45,373 | ) | | (334,764 | ) | | (85,227 | ) | | (93,785 | ) | | Accrued taxes | | | (25,370 | ) | | (30,877 | ) | | 19,078 | | | (342,454 | ) | | Accrued interest | | | (7,784 | ) | | (5,553 | ) | | (791 | ) | | (110 | ) | | Prepayment for electric service - education programs | | | 136,142 | | | - | | | 136,142 | | | - | | | Other | | | 6,357 | | | (11,403 | ) | | 18,071 | | | (5,294 | ) | | Net cash provided from (used for) operating activities | | | 202,812 | | | (99,866 | ) | | 468,910 | | | 5,157 | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | New Financing - | | | | | | | | | | | | | | | Long-term debt | | | 146,450 | | | - | | | 146,450 | | | 30,000 | | | Short-term borrowings, net | | | 16,260 | | | - | | | 47,442 | | | - | | | Redemptions and Repayments - | | | | | | | | | | | | | | | Preferred stock | | | (37,750 | ) | | - | | | (37,750 | ) | | - | | | Long-term debt | | | (244,721 | ) | | (19,809 | ) | | (260,508 | ) | | (116,810 | ) | | Short-term borrowings, net | | | - | | | (94,155 | ) | | - | | | (77,814 | ) | | Dividend Payments - | | | | | | | | | | | | | | | Common stock | | | (130,000 | ) | | (117,000 | ) | | (177,000 | ) | | (171,000 | ) | | Preferred stock | | | (658 | ) | | (659 | ) | | (1,317 | ) | | (1,220 | ) | | Net cash used for financing activities | | | (250,419 | ) | | (231,623 | ) | | (282,683 | ) | | (336,844 | ) | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | Property additions | | | (41,675 | ) | | (47,302 | ) | | (121,458 | ) | | (84,963 | ) | | Contributions to nuclear decommissioning trusts | | | (7,885 | ) | | (7,885 | ) | | (15,770 | ) | | (15,770 | ) | | Loan repayments from (loans to) associated companies, net | | | 95,498 | | | 359,878 | | | (58,540 | ) | | 408,790 | | | Other | | | 1,748 | | | 27,139 | | | 9,594 | | | 23,411 | | | Net cash provided from (used for) investing activities | | | 47,686 | | | 331,830 | | | (186,174 | ) | | 331,468 | | | | | | | | | | | | | | | | | | Net increase (decrease) in cash and cash equivalents | | | 79 | | | 341 | | | 53 | | | (219 | ) | | Cash and cash equivalents at beginning of period | | | 1,204 | | | 1,323 | | | 1,230 | | | 1,883 | | | Cash and cash equivalents at end of period | | $ | 1,283 | | $ | 1,664 | | $ | 1,283 | | $ | 1,664 | | | | | | | | | | | | | | | | | | 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 June 30, 2005,2006, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2006 and 2005 and 2004.the consolidated statement of cash flows for the six-month period ended June 30, 2006 and 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 have 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[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 7 tostatements] dated February 27, 2006, we expressed an unqualified opinion on those consolidated financial statements) dated March 7, 2005, 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.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 July 29, 2005August 4, 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. Penn’s rate restructuring plan and its associated transition charge revenue recovery was completed in 2005. 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 In 2005, the Ohio Companies and Penn 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 affect the OE Companies' comparative earnings 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 Plant and Beaver Valley 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 OE’s PLR requirements under revised purchased power arrangements for the three-year period beginning January 1, 2006 and Penn’s during 2006 (see Outlook - Regulatory Matters).
The effects on the OE Companies' results of operations in the second quarter and first six months of 2006 as compared to the same periods 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 | | Income Statement Effects | | | Three Months | | Six Months | | Increase (Decrease) | | | (In millions) | | | Revenues: | | | | | | | | Non-nuclear generating units rent | | (a | ) | $ | (44 | ) | $ | (89 | ) | | Nuclear generated KWH sales | | (b | ) | | (67 | ) | | (131 | ) | | Total - Revenues Effect | | | | | (111 | ) | | (220 | ) | | Expenses: | | | | | | | | | | | Fuel costs - nuclear | | (c | ) | | (9 | ) | | (18 | ) | | Nuclear operating costs | | (c | ) | | (43 | ) | | (89 | ) | | Provision for depreciation | | (d | ) | | (17 | ) | | (28 | ) | | General taxes | | (e | ) | | (3 | ) | | (6 | ) | | Total - Expenses Effect | | | | | (72 | ) | | (141 | ) | | Operating Income Effect | | | | | (39 | ) | | (79 | ) | | Other Income: | | | | | | | | | | | Interest income from notes receivable | | (f | ) | | 14 | | | 30 | | | Nuclear decommissioning trust earnings | | (g | ) | | (4 | ) | | (6 | ) | | Capitalized Interest | | (h | ) | | (2 | ) | | (4 | ) | | Total - Other Income Effect | | | | | 8. | | | 20. | | | Income taxes | | (i | ) | | (13 | ) | | (24 | ) | | Net Income Effect | | | | $ | (18 | ) | $ | (35 | ) | | | | | | | | | | | | | (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 second quarter of 2005 decreased2006 increased to $46$56 million from $87$46 million in the second quarter of 2004.2005. In the first six months of 2006, earnings on common stock increased to $119 million from $103 million in the same period of 2005. The decreaseincrease in earnings in both periods of 2006 primarily resulted from increaseslower expenses and increased other income, partially offset by lower revenues principally from the asset transfer effects shown in nuclear operating costs, regulatory asset amortization, general taxes andthe table above. Earnings in both periods of 2005 were also reduced by a one-time income tax charge which were partially offset by lower purchased power costs and higher regulatory asset deferrals. Duringof $36 million from the enactment of tax legislation in Ohio. Earnings in the first six months of 2005 earnings on common stock decreasedwas additionally reduced by charges relating to $103a $8.5 million from $162civil penalty payable to the Department of Justice and $10 million for environmental projects in connection with the same period of 2004. The decrease in earnings for the first half of 2005 primarily resulted from reduced operating revenues and other income, and increased nuclear operating costs, regulatory asset amortization and the one-time income tax charge. These reductions to earnings were partially offset by decreased fuel and purchased power costs, as well as, increased regulatory asset deferrals.Sammis Plant settlement (see Outlook — Environmental Matters).
Operating revenuesRevenues
Revenues decreased by $2$144 million or 0.2%20.0% in the second 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, revenues forin the second quarter of 2006 decreased $33 million, primarily resulted from a $12due to decreases of $70 million decreaseand $112 million in wholesale sales and distribution revenues, respectively, partially offset by increases in retail generation and distribution revenues of $6$125 million and $5 million, respectively. Duringreduced customer shopping incentives of $21 million.
In the first six months of 20052006 compared towith the same period in 2004, operating2005, revenues decreased by $19$284 million or 1.3%. Lower19.7%, primarily from the generation asset transfer impact summarized in the table above. Excluding the effects of the asset transfer, revenues forin the first halfsix months of 2005 were2006 decreased $64 million, primarily due to a $36decreases of $130 million decreaseand $210 million in wholesale sales and distribution revenues, respectively, partially offset by increases in retail generation and distribution revenues of $12$232 million and $7 million, respectively.reduced customer shopping incentives of $38 million.
The lower wholesale revenues in both periods of 2006 reflect the termination of a non-affiliated wholesale sales agreement and the cessation of the MSG sales arrangements under OE’s transition plan in December 2005. OE had been required to provide the MSG to non-affiliated alternative suppliers.
Lower wholesaleChanges in electric generation KWH sales and revenues forin the second quarter and the first six months of 2006 from the corresponding periods of 2005 reflected decreased sales to FES of $22 million (15.7% KWH sales decrease) and $50 million (18.1% KWH sales decrease), respectively, due to reduced nuclear generation available for sale. The decreasesare summarized in sales to FES were partially offset by increased sales of $10 million and $14 million, respectively, to non-affiliated customers (including MSG sales). Under its Ohio transition plan, OE is required to provide MSG to non-affiliated alternative suppliers (see Outlook - Regulatory Matters).the following table.
Changes in Generation KWH Sales | | Three Months | | Six Months | | Increase (Decrease) | | | | | | | Electric Generation: | | | | | | | Retail | | | 13.8 | % | | 12.5 | % | | Wholesale | | | (84.2) | % | | (82.8) | % | Net Decrease in Generation Sales | | | (31.4) | % | | (29.7) | % |
Changes in Generation Revenues | | Three Months | | Six Months | Increase (Decrease) | | (In millions) | | Retail Generation: | | | | | | | | | Residential | | $ | 41 | | $ | 84 | | | Commercial | | | 38 | | | 70 | | | Industrial | | | 46 | | | 78 | | | Total Retail Generation | | | 125 | | | 232 | | | Wholesale* | | | (70 | ) | | (130 | ) | Net Increase in Generation Revenues | | $ | 55 | | $ | 102 | | | | | | | | | | | | * Excludes impact of generation asset transfers related to nuclear generated KWH sales. | |
Increased retail generation revenues for the second quarter of 20052006 as shown in the table above resulted from increased sales to residential and commercial customers of $7 million and $1 million, respectively, partially offset by a $2 million decrease in sales to industrial customers. The increased generationhigher KWH sales to residential (12.2%) and commercial (2.4%) customers were due to warmer than normal temperatures in the second quarter of 2005 which increased air-conditioning loads. Lower industrial revenues reflected a 6.7% decreasehigher unit prices. The increase in generation KWH sales partially offset by higher composite unit prices. The industrial KWH sales decreaseprimarily resulted from increaseddecreased 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 increased by 2.6decreased by: residential - 10.4 percentage points comparedpoints; commercial - 12.5 percentage points; and industrial - 11.2 percentage points. The decrease in shopping resulted from certain alternative energy suppliers terminating their supply arrangements with OE’s shopping customers in the secondfourth quarter of 2004. Residential2005. Higher unit prices for generation reflected the rate stabilization charge and commercial customer shopping remained relatively unchanged.the fuel recovery rider that both became effective in the first quarter of 2006 under provisions of the RSP and RCP.
Retail generation revenues increased forin the first six months of 20052006 compared to the same period of 20042005 for the reasons described above. The increase in allgeneration KWH sales primarily resulted from a decrease in customer sectors (residentialshopping, as the percentage of generation services provided by alternative suppliers to total sales delivered in OE's service area decreased by: residential - $5 million,9.5 percentage points; commercial - $4 million11.8 percentage points; and industrial - $3 million). The higher residential and commercial revenues were due to increased generation KWH sales (residential - 3.3% and commercial - 3.2%). The increase in industrial revenues reflected higher composite10.2 percentage points. Higher unit prices ($5 million), partially offset by a 1.6% decrease infor generation KWH sales. Similar toreflected the second quarterimpact of 2005, industrial KWH sales decreased principally due to increased customer shopping (2.4 percentage points increase compared with the 2004 period), while residentialRSP and commercial customer shopping remained relatively unchanged.RCP described above.
Revenues fromChanges in distribution throughput increased $5 millionKWH deliveries and revenues in the second quarter and first six months of 2006 from the corresponding periods of 2005 compared with the same period in 2004. Distribution deliveries to residential customers increased $14 million due to an 11.4% increase in KWH deliveries, partially offset by lower composite unit prices. Distribution revenues from commercial and industrial customers decreased by $3 million and $7 million, respectively, primarily due to lower composite unit prices. Lower unit pricesare summarized in the commercial sector that reduced revenues by $5 million were partially offset by a 2.4% increase in KWH deliveries; industrial revenues decreased due to lower units prices ($4 million) and a 3.4% decrease in KWH deliveries. Residential and commercial KWH deliveries reflected warmer than normal temperatures in the second quarter of 2005.following table.
Changes in Distribution KWH Deliveries | Three Months | | Six Months | Increase (Decrease) | | | | | Distribution Deliveries: | | | | | | | Residential | (6.3) | % | | (3.8) | % | | Commercial | (2.2) | % | | (1.6) | % | | Industrial | 2.7 | % | | 0.5 | % | Net Decrease in Distribution Deliveries | (1.7) | % | | (1.6) | % |
Changes in Distribution Revenues | | Three Months | | Six Months | Increase (Decrease) | | (In millions) | | Residential | | $ | (48 | ) | $ | (88 | ) | | Commercial | | | (34 | ) | | (65 | ) | | Industrial | | | (30 | ) | | (57 | ) | Net Decrease in Distribution Revenues | | $ | (112 | ) | $ | (210 | ) |
Revenues fromLower distribution throughput increased $7 millionrevenues as shown in the table above in the second quarter and first six months of 2005 compared with the same period2006 reflects lower composite prices and reduced KWH deliveries. The lower unit prices in 2004both periods were due to higher revenues from residential customersthe completion of the generation-related transition cost recovery under the OE Companies’ respective rate restructuring plans in 2005, partially offset by lowerincreased transmission rates to recover MISO costs beginning in 2006 (see Outlook - Regulatory Matters). Lower distribution KWH deliveries to residential and commercial customers reflected the impact of milder weather conditions in the second quarter and first six months of 2006, compared to the same periods of 2005. KWH deliveries to industrial sector revenues. Residential revenuescustomers increased $13 million, reflecting a 4.4% increaseslightly in KWH deliveries. Commercial distribution revenues declined slightly with lower composite unit prices partially offset by a 3.0% increaseboth periods due to the recovering steel industry in KWH deliveries. Industrial distribution revenues decreased by $6 million reflecting lower composite unit prices, partially offset by a 1.6% increase in KWH distribution deliveries.the OE Companies’ service territory.
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 $1$21 million from additional credits in the second quarter of 2005 and $4$38 million in the first six months of 2005 compared to the same periods in 2004.2005. These revenue reductions, arewhich were deferred for future recovery from customers under OE’s transition plan and dodid not affect current period earnings, (Seeceased in 2006. The deferred shopping incentives (Extended RTC) are now being recovered under the RCP (see Outlook - Regulatory Matters below)Matters).
Changes in electric generation sales and distribution deliveries in the second quarter and first six months of 2005 from the corresponding periods of 2004 are summarized in the following table:
| | | | | | | Changes in KWH Sales | | Three Months | | Six Months | | Increase (Decrease) | | | | | | | Electric Generation: | | | | | | | Retail | | | 1.6 | % | | 1.4 | % | | Wholesale | | | (9.8 | )% | | (13.6 | )% | Total Electric Generation Sales | | | (4.0 | )% | | (5.8 | )% | | | | | | | | | | | Distribution Deliveries: | | | | | | | | | Residential | | | 11.4 | % | | 4.4 | % | | Commercial | | | 2.4 | % | | 3.0 | % | | Industrial | | | (3.4 | )% | | 1.6 | % | Total Distribution Deliveries | | | 2.8 | % | | 3.0 | % | | | | | | | | | |
Operating Expenses and Taxes
Total operating expenses and taxes increaseddecreased by $39$82 million in the second quarter of 2006 and $28$181 million in the first six months of 20052006 from the same periods 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 | | Three Months | | Six Months | | Expenses - Changes | | | Three Months | | Six Months | Increase (Decrease) | | (In millions) | | (In millions) | | Fuel costs | | $ | (2 | ) | $ | (5 | ) | | | Purchased power costs | | | (10 | ) | | (14 | ) | | $ | 66 | | $ | 102 | | | Nuclear operating costs | | | 18 | | | 34 | | | | (6 | ) | | (14 | ) | | Other operating costs | | | 4 | | | 2 | | | | (4 | ) | | 4 | | | Provision for depreciation | | | 1 | | | (2 | ) | | | 2 | | | 6 | | | Amortization of regulatory assets | | | 10 | | | 8 | | | | (66 | ) | | (124 | ) | | Deferral of new regulatory assets | | | (14 | ) | | (20 | ) | | | (3 | ) | | (15 | ) | | General taxes | | | 7 | | | 6 | | | | 1 | | | 2 | | | Income taxes | | | 25 | | | 19 | | | Net increase in operating expenses and taxes | | $ | 39 | | $ | 28 | | | Net decrease in expenses | | | $ | (10 | ) | $ | (39 | ) | | | | | | | | | | | | | | | | |
Lower fuelIncreased purchased power costs in the second quarter and first six months of 2005, compared2006 reflected higher unit prices associated with the same periods of 2004, resulted from decreased nuclear generation - down 15.7% and 18.1%, respectively. Purchasednew power costs were lower in both periods of 2005, reflecting lower unit costs andsupply agreement with FES, partially offset by a reductiondecrease in KWH purchased into meet the first halflower net generation sales requirements. Excluding the effects of 2005. KWH purchases were relatively unchanged in the second quarter. Nucleargeneration asset transfers, the lower nuclear operating costs increasedfor OE’s nuclear leasehold interests were primarily due to the costs fromabsence in 2006 of the Beaver Valley Unit 2 refueling outage (started April 4, 2005) and to a lesser extent from the Perry Unit 1Nuclear Power Plant scheduled refueling outage initiated in the first quarter of 2005(including an unplanned extension) that was completed on May 6, 2005. There were no nuclear refueling outagesThe decrease in other operating costs during the second quarter of 2006 was primarily due to lower associated company (FES) transmission expenses as a result of alternative energy suppliers terminating their supply arrangements with OE’s shopping customer in the same periods last year.fourth quarter of 2005. The increase in other operating costs in the first six months of 2006 was primarily due to increased transmission expenses related to MISO Day 2 operations that began on April 1, 2005.
Excluding the effects of the generation asset transfers, higher depreciation expense in the second quarter and first six months of 2005, compared to the same periods of 2004, resulted primarily from higher vegetation management costs and increased MISO transmission expenses, partially offset by lower employee benefits expenses.
Depreciation in the second quarter of 2005 was relatively unchanged compared2006 reflected capital additions subsequent to the second quarter of 2004. The decrease in the first six months2005. Lower amortization of 2005 compared with the same period of 2004 was attributable to revised estimated service life assumptions for fossil generating plants. Higher regulatory asset amortizationassets in both periods was primarily due to increasedthe completion of the generation-related transition cost amortization under the OE Companies' respective transition plans, partially offset by the amortization of transitiondeferred MISO costs being recovered under the Rate Stabilization Plan. Deferralin 2006. The higher deferrals of new regulatory assets decreased expenses by $13 million in both the second quarter and the first six months of 2005 primarily from the PUCO-approved MISO deferrals and related interest beginning in the second quarter of 2005 (see Outlook - Regulatory Matters).
General taxes increased in the second quarter and first six months of 2005 compared to2006 primarily resulted from the same periodsdeferral of 2004, primarily due tofuel ($14 million and $25 million, respectively) and distribution costs ($22 million and $39 million, respectively) under the absenceRCP, partially offset by lower MISO cost deferrals ($12 million and $11 million, respectively) and the decrease in shopping incentive deferrals ($21 million and $38 million, respectively) which ceased in 2006 under the Ohio transition plan. The deferral of a $6 million Pennsylvania property tax refund recorded ininterest on the second quarter of 2004.unamortized shopping incentive balances continues under the RCP.
Income taxes increased in the second quarter and first six months of 2005 compared to the same periods of 2004, primarily due toExcluding the effects of newthe generation asset transfers, higher general taxes in both periods reflects the phase-in of the Ohio commercial activity tax legislation in Ohio (see Note 12 to consolidated financial statements). On June 30, 2005, the State of Ohio enacted new tax legislation that creates a new Commercial Activity Tax (CAT), which is based on qualifying "taxable gross receipts" and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax isbecame effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and personal property tax is phased-out over a four-year period at a rate of approximately 25%, annually beginning with the year ended 2005. During the phase-out period the Ohio income tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period.
As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. Accordingly, OE’s income tax expense increased by $36 million for the three and six-month periods ended June 30, 2005. Income tax expense was reduced during the three and six-month periods ended June 30, 2005 by approximately $5 million by the initial phase-out of the Ohio income tax.78
Other Income
Other income decreased $16increased $14 million in the second quarter of 2006 and $47 million in the first six months of 20052006 as compared with the same periodperiods of 2004,2005, primarily due to anthe effects of the generation asset transfers. Excluding the effects of the generation asset transfers, the $5 million increase in the second quarter is primarily due to lower interest expense, reflecting debt redemptions subsequent to the second quarter of 2005.
Excluding the effects of the generation asset transfers, the $28 million increase in the first six months is primarily due to lower interest expense and the absence in 2006 of the 2005 charges of $8.5 million for a civil penalty payable to the Department of JusticeDOJ and a $10 million liability for environmental projects recognized in connection with the Sammis PlantNew Source Review settlement (see Outlook - Environmental Matters).
Net Interest ChargesIncome Taxes
Net interest charges continued to trend lower, decreasing by $0.4Income taxes decreased $60 million in the second quarter of 2006 and $2$75 million in the first six months of 20052006 compared with the same periods of 2004, reflecting $2002005. Excluding the effects of the generation asset transfer, income taxes decreased $47 million in the second quarter of debt redemptions since July 1, 2004.2006 and $50 million in the first six months of 2006. As a result of new Ohio tax legislation in 2005, OE wrote off $36 million in net deferred tax benefits in the second quarter of 2005. The remainder of the net change in both the second quarter and the six-month period was mainly 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.
Capital Resources and Liquidity
OE’s cash requirements in 20052006 for operating expenses, construction expenditures and scheduled debt maturities and preferred stock redemptions are expected to be met without increasing OE’s net debtwith cash from operations, short-term credit arrangements and funds from capital markets. OE repurchased $500 million of common stock from FirstEnergy and redeemed $64 million of preferred stock outstanding.in July 2006 with proceeds of senior notes issued in June 2006. Available borrowing capacity under credit facilities will be used to manage working capital requirements. Thereafter, OE expects to use a combination of cash from operations and funds from the capital markets.
Changes in Cash Position
AsOE had $545 million of June 30, 2005, OE's cash and cash equivalents as of approximatelyJune 30, 2006 compared with $1 million remained unchanged from itsas of December 31, 2004 balance.2005. The major sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided from operating activities during the second quarter and first six months of 2005,2006, compared with the corresponding periodsperiod in 2004 were2005, was as follows: | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | Operating Cash Flows | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In millions) | | | | | | | | | | | | | Cash earnings (*) | | $ | 144 | | $ | 153 | | $ | 329 | | $ | 383 | | | Working capital and other | | | 59 | | | (253 | ) | | 140 | | | (378 | ) | | Total cash flows form operating activities | | $ | 203 | | $ | (100 | ) | $ | 469 | | $ | 5 | | | | | | | | | | | | | | | | | (*) Cash earnings is a non-GAAP measure (see reconciliation below). | | | | | | | | | | |
| | | Six Months Ended | | | | | June 30, | | Operating Cash Flows | | 2006 | | 2005 | | | | | | (In millions) | | Cash earnings (1) | | $ | 129 | | $ | 329 | | | Working capital and other | | | 90 | | | 135 | | | Net cash provided from operating activities | | $ | 219 | | $ | 464 | | | | | | | | | | |
(1)Cash earnings are a non-GAAP measure (see reconciliation below).
Cash earnings as disclosed in(in the table above,above) are not a measure of performance calculated in accordance with GAAP. OE 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 | | Six Months Ended | | | Six Months Ended | | | | | June 30, | | June 30, | | | June 30, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | | | | | | (In millions) | | | Net income (GAAP) | | $ | 47 | | $ | 87 | | $ | 104 | | $ | 163 | | | $ | 123 | | $ | 104 | | | Non-cash charges (credits): | | | | | | | | | | | | | | | | | | | | | | Provision for depreciation | | | 32 | | | 30 | | | 58 | | | 60 | | | | 36 | | | 58 | | | Amortization of regulatory assets | | | 110 | | | 100 | | | 221 | | | 214 | | | | 97 | | | 221 | | | Deferral of new regulatory assets | | | | (78 | ) | | (64 | ) | | Nuclear fuel and capital lease amortization | | | | (11 | ) | | 19 | | | Amortization of electric service obligation | | | | (17 | ) | | (4 | ) | | Amortization of lease costs | | | (36) | | | (35) | | | (3) | | | (2) | | | | (4 | ) | | (3 | ) | | Nuclear fuel and capital lease amortization | | | 9 | | | 11 | | | 19 | | | 22 | | | | Deferral of new regulatory assets | | | (39) | | | (25) | | | (64) | | | (44) | | | | Deferred income taxes and investment tax credits, net | | | 19 | | | (21) | | | (5) | | | (51) | | | | (17 | ) | | (5 | ) | | Other non-cash items | | | 2 | | | 6 | | | (1) | | | 21 | | | | Accrued compensation and retirement benefits | | | | -- | | | 3 | | | Cash earnings (Non-GAAP) | | $ | 144 | | $ | 153 | | $ | 329 | | $ | 383 | | | $ | 129 | | $ | 329 | | | | | | | | | | | | | | | | | | | | | | | |
Net cash provided from operating activities increased $303decreased $245 million in the second quarterfirst six months of 2005,2006, compared with the second quarter of 2004,same period in 2005, due to a $312$45 million increasedecrease from changes in working capital partially offset byand a $9$200 million decrease in cash earnings as described above and under "Results“Results from Operations".Operations.” The increasedecrease in working capital primarily reflects net changesthe absence in accounts payable and accounts receivable to associated companies2006 of $152 million and $136 million of funds received for prepaid electric service under the Energy for Education program.
Net cash from operating activities increased $464 million in the first six months of 2005, compared with the same period in 2004, due to a $518 million increase from changes in working capital, partially offset by a $54 million decrease in cash earnings as described above and under "Results from Operations". The increase in working capital primarily reflects changes in accrued taxes of $362 million and $136 million of funds received for the Energy for Education program. The accrued taxes change includes a $249program in 2005, partially offset by changes in prepayments and other current assets of $78 million reallocationand accounts payable of tax liabilities among the FirstEnergy subsidiaries pursuant to the tax sharing agreement in the first quarter of 2004.$39 million.
Cash Flows From Financing Activities
Net cash used forprovided from financing activities increased to $250 million in the second quarter of 2005 from $232 million in the second quarter of 2004. The increase primarily resulted from a $13 million increase in common stock dividends to FirstEnergy and a $6 million increase in net debt and preferred stock redemptions. Net cash used for financing activities decreased to $283$240 million in the first six months of 20052006 from $337$283 million used for financing activities in the first six months of 2005. The increase primarily reflected more long-term debt financing, and decreases of $151 million in the same periodredemptions of 2004. The decrease was due to a $60 million decrease in netpreferred stock and long-term debt and preferred$142 million in common stock redemptions,dividend payments to FirstEnergy, partially offset by a $6 million increase in common stock dividendshigher repayments of short-term borrowings to FirstEnergy.associated companies. On May 16, 2005, Penn redeemed 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, including accrued dividends to the date of redemption.
OE had approximately $599 million$1.1 billion of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $226$25 million of short-term indebtedness as of June 30, 2005.2006. OE has authorization from the PUCO to incur short-term debt of up to $500 million, (includingwhich is available through 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$44 million (includingas of June 30, 2006, and also has access to the bank facility and the utility money pool). In addition, pool.
OES Capital is a wholly 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 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 June 30, 2006, the facility was 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 $25 million under a receivables financing arrangement.arrangement which expires July 28, 2007. 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 June 30, 2005,2006, the facility was drawn for $20$19 million. On July 15, 2005, the facility was renewed until June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.
On April 6, 2004, Ohio Air Quality Development Authority and Ohio Water Development Authority pollution control bonds aggregating $100 million and $6.45 million, respectively, were refunded by OE. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance and secured by FMB.
On July 1, 2005, Ohio Water Development Authority pollution control bonds aggregating $40 million were refunded by OE. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance. OE provided FMB collateral to the bond insurer.
As of June 30, 2006, OE and Penn had the aggregate capability to issue approximately $1.8 billion$592 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 $668$735 million as of June 30, 2005.2006. Based upon applicable earnings coverage tests in their respective charters, OE and Penn could issue a total of $2.5$2.7 billion of preferred stock (assuming no additional debt was issued) as of June 30, 2005.2006. As a result of OE redeeming all of its outstanding preferred stock on July 7, 2006, the applicable earnings coverage test is inoperable for OE. In the event that OE issues preferred stock in the future, the applicable earnings coverage test will govern the amount of additional preferred stock that OE may issue.
As of June 30, 2006, OE had approximately $400 million of capacity remaining unused under its existing shelf registration.
On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility.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 andor the commitment termination date, as the same may be extended. OE's and Penn’s borrowing limitslimit under the facility are $550 million. The facility replaced FirstEnergy’s $375is $500 million and $1 billion three-year credit agreements and OE’s $125Penn’s is $50 million, three-year credit agreement, as well as OE’s recently-expired $250 million two-year credit agreement.subject in each case to applicable regulatory approvals.
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 $726 million as of June 30, 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 June 30, 2006, debt to total capitalization as defined under the revolving credit facility was 40% for OE and 34% for Penn.
The facility does not contain any provisions that either restricts the ability of OE and Penn to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. 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 and Penn have the ability to borrow from their regulated affiliates and FirstEnergy to meet their 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 second quarterfirst six months of 20052006 was 2.93%4.86%.
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 suchsecurities is stable. The ratings outlook from Moody's and Fitch on all securities is positive.
On May 16, 2005, S&P affirmed its 'BBB-' corporate credit ratings on FirstEnergy Corp.April 3, 2006, pollution control notes that were formerly obligations of OE and its unitsPenn were refinanced and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmationbecame obligations of FGCO and outlook revision reflects the successful restart of the three nuclear units from their respective outages that occurred during the first half of 2005. S&P noted that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projected and as its nuclear operations further stabilize.
On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s rating outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in its outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemmingNGC. The proceeds from the applicationrefinancings were used to repay a portion of free cash flow. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continuestheir associated company notes payable to achieve planned improvements in its operationsPenn and balance sheet.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 provided from investing activities totaled $48was $86 million in the second quarterfirst six months of 20052006 compared with $332to $181 million used for investing activities in the same period in 2004.first six months of 2005. The $284 million change for the second quarter resulted primarily from a $264$171 million decreaseincrease in loan repayments from associated companies and a $72 million decrease in property additions. Duringadditions, which reflects the first six monthsimpact of 2005, net cash used for investing activities totaled $186 million compared to net cash provided from investing activities of $331 million in the same period of 2004. The $518 million change resulted primarily from a $467 million position change from receiving loan repayments from associated companies in 2004 to issuing loans to associated companies in 2005, and a $36 million increase in property additions.generation asset transfers.
During the second half of 2005,2006, capital requirements for property additions and capital leases are expected to be approximately $133 million, including $17 million for nuclear fuel.$46 million. OE has additional requirements of approximately $24$2 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 and short-term credit arrangements. OE’s capital spending for the period 2005-20072006-2010 is expected to be about $667approximately $624 million, (excluding nuclear fuel), of which approximately $218$108 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $147 million, of which about $35 million applies to 2005. During the same period, its nuclear fuel investments are expected to be reduced by approximately $129 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 $663$640 million as of June 30, 2005.2006.
Equity Price Risk
Included in OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $251$70 million and $248$67 million as of June 30, 20052006 and December 31, 2004,2005, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $25$7 million reduction in fair value as of June 30, 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
FirstEnergy Intra-System Generation Asset Transfers Regulatory assets and liabilities are costs which have been authorized by the PUCO, the PPUC and the FERC for recovery from or credit to customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets and liabilities would have been charged to income as incurred. All regulatory assets are expected to be recovered under the provisions of the OE Companies’ transition plans and rate restructuring plans. OE‘s regulatory assets were $756 million and $775 million as of June 30, 2006 and December 31, 2005, respectively. Penn had net regulatory liabilities of $59 million as of June 30, 2006 and December 31, 2005, which are included in Other Noncurrent Liabilities on the Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005.
On May 13, 2005, Penn, and on May 18, 2005, OE, CEI and TE, entered into certain agreements described below (Agreements) implementing a series of intra-system generation asset transfers. When concluded, the asset transfers will result in the respective undivided ownership interests ofOctober 21, 2003 the Ohio Companies and Penn in FirstEnergy’s nuclear, fossil and hydroelectric plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include leasehold interests of CEI, TE and OE in plants that are currently subject to sale and leaseback arrangements with non-affiliates.
These transactions are being undertaken in connectionfiled their RSP case with the PUCO. On August 5, 2004, the Ohio Companies’Companies accepted the RSP as modified 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 transferin an August 4, 2004 Entry on Rehearing, subject to a separate corporate entity. FENOC, a subsidiary of FirstEnergy, currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a master facility lease, leases the non-nuclear generation assets to be transferred and operates and maintains those assets.CBP. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.
As contemplated by the Agreements, the Ohio Companies and Penn intend to transfer their respective interests in the nuclear generation assets to NGC through, in the case of OE and Penn, a spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FGCO intends to exercise a purchase option under the Master Lease to acquire the non-nuclear generation assets to be transferred by the Ohio Companies and Penn at the values approved in the Ohio Transition Case.
Consummation of the transactions contemplated by each of the Agreements is subject to receipt of all necessary regulatory authorizations and other consents and approvals. FirstEnergy currently expects to complete the various asset transfers in the second half of 2005.
Regulatory Matters
In 2001, Ohio customer rates were restructuredRSP was intended to establish separate charges for transmission, distribution, transition cost recoverygeneration service rates beginning January 1, 2006, in response to the PUCO’s concerns about price 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, 2008 unless the PUCO accepts future competitive bid results prior tosupply uncertainty following the end of that period under the revised Rate Stabilization Plan. As part of OE'sOhio Companies' 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 (MSG) 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 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 economicmarket development efforts. Onperiod. In 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 the proceeding as well as the associated entries on rehearing. Other key componentsOn September 28, 2005, the Supreme Court of Ohio heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order with respect to the approval of the Rate Stabilization Plan includerate stabilization charge, approval of the following:shopping credits, the granting of interest on shopping credit incentive deferral amounts, and approval of the Ohio Companies’ financial separation plan. It remanded one matter back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient means for customer participation in the competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion for Reconsideration with the Supreme Court of Ohio which was denied by the Court on June 21, 2006. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation, requesting the PUCO to initiate a proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. Separately, the OCC and NOAC also submitted to the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket to address the Court’s concern.
The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. 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 balances 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. |
The following table provides OE’s estimated net 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 | | $ | 177 | | 2007 | | | 180 | | 2008 | | | 208 | Total Amortization | | $ | 565 | | | | | |
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. 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:
| | · | Amortization period for transition costs being recovered through the RTC for OE extends to as late as 2007;Recognize fuel and distribution deferrals commencing January 1, 2006; |
| | | | | · | Deferral of interest costsRecognize distribution deferrals on a monthly basis prior to review by the accumulated customer shopping incentives as new regulatory assets; andPUCO Staff; |
| | | | | · | AbilityClarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and | | | | | · | Clarify that distribution expenditures do not have to request increasesbe “accelerated” in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.order to be deferred. | | | |
On May 27, 2005, OE filed an application with 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 establish a generation rate adjustment rider undersimply accepting the Rate Stabilization Plan.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 application seeksOhio Companies responded to implement recovery of increased fuel costs from 2006 through 2008 applicable to OE’s retail customers through a tariff rider to be implemented January 1,the applications for rehearing on February 13, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider is seeking to recover all costs above the baseline. Various parties including the OCC have intervened in this case. OE has received discovery requests from the OCC and the PUCO staff. A procedural schedule has been establishedIn 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 notices of appeal with a hearing scheduled for October 4, 2005.
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 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. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approvedSupreme Court of Ohio alleging various errors made by the PUCO for OE in 2004. Any acceptance of future competitive bid results would terminateits order approving the Rate Stabilization Plan pricing, but notRCP. The Ohio Companies’ Motion to Intervene in the related approved accounting, and not until twelve months afterappeals was granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO authorizes such termination.and the Ohio Companies. The Appellees’ Merit Briefs are due on August 4, 2006. Appellants’ Reply Briefs will then be due on August 24, 2006.
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 seekssought recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $14 million per year; however, OE anticipates that this amount will increase. OEThe Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted thereafter each July 1. OE1 thereafter. The parties reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, whichagreement that was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by OE, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. If the settlement stipulation is approved by the PUCO the actual amounts to beon August 31, 2005. The incremental transmission and ancillary service revenues recovered through thefrom January 1 through June 30, 2006 rider will be submittedwere approximately $31 million. That amount included the recovery of a portion of the 2005 deferred MISO expenses as described below. On May 1, 2006, OE filed a modification to the PUCO on or before November 1, 2005.rider to determine revenues ($71 million) from July 2006 through June 2007.
The second application seekssought 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 OEthe Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in the MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Deferral of allPermission to defer costs incurred prior to December 31,30, 2004 was denied. The PUCO also authorized OEthe Ohio Companies to accrue carrying charges on the deferred balances. An application filed withOn August 31, 2005, the PUCO to recover theseOCC appealed the PUCO's decision. On January 20, 2006, the OCC sought rehearing of the PUCO’s approval of the recovery of deferred charges over a five-year periodcosts through the rider beginning in 2006, is pending. The OCC, OPAE and OE each filed applications for rehearing. OE sought authority to defer the transmission and ancillary service related costs incurred during the period OctoberJanuary 1, 20032006 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, theJune 30, 2006. The PUCO denied OE's and OCC’s applications and, at the request of OE, struck as untimely OPAE’s application. OE andOCC's application on February 6, 2006. On March 23, 2006, the OCC have sixty days from that dateappealed the PUCO's order to file a notice of appeal with the Ohio Supreme Court. 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 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 were heard on May 10, 2006. The Ohio Companies are unable to predict when a decision may be issued.
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 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. To the extent that an affiliate of Penn supplies a portion of the PLR load included in the RFP, authorization to make the affiliate sale must be obtained from the FERC. Hearings before the PPUC 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. On April 20, 2006, the PPUC approved the Recommended Decision with additional modifications to use an RFP process to obtain Penn's power supply requirements after 2006 through two separate solicitations. An initial solicitation was held for Penn in May 2006 with all tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results for the first solicitation. On July 18, 2006, the second PLR solicitation was held for Penn. The tranches for the Residential Group and Small Commercial Group were fully subscribed. However, supply was only acquired for three of the five tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved the submissions for the second bid. A residual solicitation is scheduled to be held on August 15, 2006 for the two remaining Large Commercial Group tranches. Acceptance of the winning bids is subject to approval by the PPUC. On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of April 28, 2006 and May 4, 2006, which together decided the issues associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the Commonwealth Court to review the PPUC’s decision to deny its recovery of certain PLR costs via a reconciliation mechanism and its decision to impose a geographic limitation on the sources of alternative energy credits. On June 7, 2006, the PaDEP filed a Petition for Review appealing the PPUC’s ruling on the method by which alternative energy credits may be acquired and traded. Penn is unable to predict the outcome of this appeal. OE and Penn record as regulatory assets costs which have been authorized
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 the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. OE’s regulatory assets asa period of June 30, 2005 and December 31, 2004, were $0.9 billion and $1.1 billion, respectively. OE is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $274 million as of June 30, 2005 andthree years beginning January 1, 2006. The Ohio Companies will be recovered throughrelieved of their obligation to obtain PLR power requirements from FES if the Ohio CBP results in a surcharge ratelower 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 RTC rateretail 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 through two separate solicitations. An initial solicitation was held for Penn in effect whenMay 2006 with all tranches fully subscribed. On June 2, 2006, the transition costs have beenPPUC approved the bid results for the first solicitation. On July 18, 2006, the second PLR solicitation was held for Penn. The tranches for the Residential Group and Small Commercial Group were fully recovered. Recoverysubscribed. However, supply was only acquired for three of the new regulatory assets will begin at that time and amortizationfive tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved the submission for the second bid. A residual solicitation is scheduled to be held on August 15, 2006 for the two remaining Large Commercial Group tranches. Acceptance of the regulatory assetswinning bids is subject to approval by the PPUC.
On December 29, 2005, the FERC issued an order setting the two power sales agreements for each accounting period willhearing. The order criticized the Ohio CBP, 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. Under the procedural schedule, approved in this case, FES expected an initial decision to be equalissued in late January 2007. However, on July 14, 2006, the Chief Judge granted the joint motion of FES and the Trial Staff to appoint a settlement judge in this proceeding. The procedural schedule has been suspended pending negotiations among the surcharge revenue recognized during that period. Penn's net regulatory asset components aggregate as net regulatory liabilities of approximately $37 million and $18 million, and are included in Other Noncurrent Liabilities on the Consolidated Balance Sheet as of June 30, 2005 and December 31, 2004, respectively.parties.
See Note 1411 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.
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.
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 W. H. Sammis Plant-
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, including 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 in the form of a Consent Decree that was approved by the Court on July 11, 2005, and 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 capital expenditures currently estimatedand provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Those requirements will be $1.1 billion (primarily in the 2008 to 2011 time period).responsibility of FGCO. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchasepurchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties payablepaid by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized 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.
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.
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.
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.projects.
See Note 13(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, 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 websiteWeb site (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. FirstEnergy is also is proceeding with the implementation of the 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 new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that theequipment. The 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 FirstEnergy’s 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.
Three substantially similar actions were filed in various Ohio State courts by plaintiffs seeking FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All threeoutage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. Two ofIn these cases were refiled at the PUCO, one in 2004 and another in 2005. In each, individual complainants—three in one case and four in the other—seek damages related to the outages and also seeksought to represent others as part of a class action. FirstEnergy has filed responsive pleadings to both cases. The PUCO has dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. BothThree other pending PUCO complaint cases, are otherwise currently pending further proceedings. In addition to the two cases that were refiled at the PUCO, the Ohio Companies were namedfiled by various insurance carriers either in their own name 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 was filed on August 25, 2004 against FirstEnergysubrogees or in the New York State Supreme Court.name of their insured. In thiseach of these three cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, several plaintiffs in the New York City metropolitan area allege that they sufferedfrom 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 power outages. None of the plaintiffs2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy affiliate.company. The sixth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It is currently expected that this case will be summarily dismissed, although the Motion is still pending. 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 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. 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 that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed an amended complaint and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. These motions are pending. Additionally, on June 23, 2006, one of the insurance carrier complainants filed an appeal with the Ohio Supreme Court on October 22, 2004. No timetableover the PUCO’s denial of their motion for a decisionrehearing on the motionissue of the admissibility of the Task Force Report and the dismissal of FirstEnergy Corp. as a respondent. Briefing is expected to dismiss has been establishedbe completed on this appeal by mid-September. It is unknown when the Court.Supreme Court will rule on the appeal. No damage estimate has been provided and thusof potential liability has not been determined.is available for any of these cases.
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- 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 preceding 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 (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which will include owned portions of the plant).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. On May 26,September 28, 2005, the NRC heldsent a public meetingCAL to discuss its oversight ofFENOC describing commitments that FENOC had made to improve the performance at the Perry Plant. While the NRCPlant and stated that the plantCAL 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 safely,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 overall performance had not substantially improved sinceof the heightened inspectionfacility was initiated.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-
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 now repealed 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 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.
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. Both filings were consolidated for hearing and decision described above. 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. On May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s complaint and approving the related tariffs, thus affirming OE’s entitlement to recovery of its transition charges. The City of Huron filed an application for rehearing of the PUCO’s decision on June 9, 2006 and OE filed a memorandum in opposition to that application on June 19, 2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The City of Huron has 60 days from the denial of rehearing to appeal the PUCO’s decision. 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'sFirstEnergy’s or its subsidiaries'subsidiaries’ financial condition, and results of operations.operations and cash flows. See Note 13(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 InterpretationsNEW ACCOUNTING STANDARDS AND INTERPRETATIONS
| SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"FIN 48 - “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109.”
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In May 2005,June 2006, the FASB issued SFAS 154 to changeFIN 48 which clarifies the requirementsaccounting for accounting and reporting a changeuncertainty in accounting principle. It applies to all voluntary changesincome taxes recognized in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of changesa tax position taken or expected to be taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in accounting principle, unlessinterim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation will be a two-step process. The first step will determine if it is impracticablemore likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine either the period-specific effects or the cumulative effectamount of the change. In those instances, this Statement requires that the new accounting principle be appliedbenefit to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assetsrecognize in the statement of financial position) for that period rather than being reported in an income statement.statements. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement areinterpretation is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. OE will adopt this Statement effective January 1, 2006.
| FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
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On March 30, 2005, the FASB issued FIN 47 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 second 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. Therefore, OE will adopt this Interpretation in the fourth quarter of 2005. OE is currently evaluating the effectimpact of this standard will have on its financial statements.Statement.
| EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
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In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, OE continues to evaluate its investments as required by existing authoritative guidance.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | | | | | | | | Three Months Ended | | | | Six Months Ended | | | | | June 30, | | | | June 30, | | | | | 2005 | | 2004 | | | | 2005 | | 2004 | | | | | (In thousands) | | STATEMENTS OF INCOME | | | | | | | | | | | | | | | | | | | | | | | | | OPERATING REVENUES | | $ | 448,747 | | $ | 440,876 | | | | | $ | 881,920 | | $ | 867,411 | | | | | | | | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | | | | Fuel | | | 21,110 | | | 19,376 | | | | | | 39,437 | | | 36,572 | | | Purchased power | | | 138,842 | | | 136,505 | | | | | | 281,726 | | | 271,182 | | | Nuclear operating costs | | | 36,786 | | | 18,521 | | | | | | 95,513 | | | 51,236 | | | Other operating costs | | | 74,711 | | | 79,634 | | | | | | 138,284 | | | 143,661 | | | Provision for depreciation | | | 33,387 | | | 32,776 | | | | | | 64,502 | | | 64,964 | | | Amortization of regulatory assets | | | 55,016 | | | 50,022 | | | | | | 109,042 | | | 98,090 | | | Deferral of new regulatory assets | | | (40,701 | ) | | (32,956 | ) | | | | | (65,989 | ) | | (51,436 | ) | | General taxes | | | 36,605 | | | 34,480 | | | | | | 75,492 | | | 73,298 | | | Income taxes | | | 34,734 | | | 25,161 | | | | | | 39,611 | | | 29,174 | | | Total operating expenses and taxes | | | 390,490 | | | 363,519 | | | | | | 777,618 | | | 716,741 | | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 58,257 | | | 77,357 | | | | | | 104,302 | | | 150,670 | | | | | | | | | | | | | | | | | | | | OTHER INCOME (net of income taxes) | | | 9,270 | | | 9,494 | | | | | | 13,574 | | | 21,221 | | | | | | | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | | | | | | | Interest on long-term debt | | | 28,410 | | | 36,695 | | | | | | 56,362 | | | 68,906 | | | Allowance for borrowed funds used during construction | | | (1,294 | ) | | (1,015 | ) | | | | | (883 | ) | | (2,726 | ) | | Other interest expense | | | 1,742 | | | 1,446 | | | | | | 8,256 | | | 7,511 | | | Net interest charges | | | 28,858 | | | 37,126 | | | | | | 63,735 | | | 73,691 | | | | | | | | | | | | | | | | | | | | NET INCOME | | | 38,669 | | | 49,725 | | | | | | 54,141 | | | 98,200 | | | | | | | | | | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | - | | | 1,755 | | | | | | 2,918 | | | 3,499 | | | | | | | | | | | | | | | | | | | | EARNINGS ON COMMON STOCK | | $ | 38,669 | | $ | 47,970 | | | | | $ | 51,223 | | $ | 94,701 | | | | | | | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 38,669 | | $ | 49,725 | | | | | $ | 54,141 | | $ | 98,200 | | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | | Unrealized loss on available for sale securities | | | (1,349 | ) | | (10,371 | ) | | | | | (2,570 | ) | | (2,323 | ) | | Income tax benefit related to other comprehensive income | | | 419 | | | 4,248 | | | | | | 923 | | | 952 | | | Other comprehensive income (loss), net of tax | | | (930 | ) | | (6,123 | ) | | | | | (1,647 | ) | | (1,371 | ) | | | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 37,739 | | $ | 43,602 | | | | | $ | 52,494 | | $ | 96,829 | | | | | | | | | | | | | | | | | | | | | 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 INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | Three Months Ended June 30, | | | Six Months Ended June 30, | | | | | 2006 | | | 2005 | | | 2006 | | | 2005 | | | | | | (In thousands) | | STATEMENTS OF INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | REVENUES | | $ | 432,371 | | $ | 448,747 | | $ | 840,181 | | $ | 881,920 | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | Fuel | | | 13,413 | | | 21,110 | | | 26,976 | | | 39,437 | | | Purchased power | | | 157,942 | | | 138,842 | | | 301,711 | | | 281,726 | | | Nuclear operating costs | | | - | | | 36,786 | | | - | | | 95,513 | | | Other operating costs | | | 68,436 | | | 74,711 | | | 141,331 | | | 138,284 | | | Provision for depreciation | | | 11,050 | | | 33,387 | | | 28,251 | | | 64,502 | | | Amortization of regulatory assets | | | 29,476 | | | 55,016 | | | 61,006 | | | 109,042 | | | Deferral of new regulatory assets | | | (31,698 | ) | | (40,701 | ) | | (62,223 | ) | | (65,989 | ) | | General taxes | | | 31,510 | | | 36,605 | | | 66,580 | | | 75,492 | | | Total expenses | | | 280,129 | | | 355,756 | | | 563,632 | | | 738,007 | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 152,242 | | | 92,991 | | | 276,549 | | | 143,913 | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | Investment income | | | 24,674 | | | 14,049 | | | 51,610 | | | 29,197 | | | Miscellaneous income (expense) | | | 5,642 | | | (2,292 | ) | | 5,396 | | | (8,764 | ) | | Interest expense | | | (34,634 | ) | | (30,152 | ) | | (69,366 | ) | | (64,618 | ) | | Capitalized interest | | | 837 | | | 1,294 | | | 1,510 | | | 883 | | | Total other income (expense) | | | (3,481 | ) | | (17,101 | ) | | (10,850 | ) | | (43,302 | ) | | | | | | | | | | | | | | | | INCOME TAXES | | | 57,709 | | | 37,221 | | | 102,234 | | | 46,470 | | | | | | | | | | | | | | | | | NET INCOME | | | 91,052 | | | 38,669 | | | 163,465 | | | 54,141 | | | | | | | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | - | | | - | | | - | | | 2,918 | | | | | | | | | | | | | | | | | EARNINGS ON COMMON STOCK | | $ | 91,052 | | $ | 38,669 | | $ | 163,465 | | $ | 51,223 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 91,052 | | $ | 38,669 | | $ | 163,465 | | $ | 54,141 | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | Unrealized loss on available for sale securities | | | - | | | (1,349 | ) | | - | | | (2,570 | ) | | Income tax benefit related to other comprehensive income | | | - | | | 419 | | | - | | | 923 | | | Other comprehensive loss, net of tax | | | - | | | (930 | ) | | - | | | (1,647 | ) | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 91,052 | | $ | 37,739 | | $ | 163,465 | | $ | 52,494 | | | | | | | | | | | | | | | | | 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) | | | | | June 30, | | December 31, | | | | | 2005 | | 2004 | | | | | (In thousands) | | ASSETS | | | | | | UTILITY PLANT: | | | | | | | In service | | $ | 4,497,877 | | $ | 4,418,313 | | | Less - Accumulated provision for depreciation | | | 2,000,871 | | | 1,961,737 | | | | | | 2,497,006 | | | 2,456,576 | | | Construction work in progress - | | | | | | | | | Electric plant | | | 79,897 | | | 85,258 | | | Nuclear fuel | | | 4,330 | | | 30,827 | | | | | | 84,227 | | | 116,085 | | | | | | 2,581,233 | | | 2,572,661 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Investment in lessor notes | | | 564,172 | | | 596,645 | | | Nuclear plant decommissioning trusts | | | 401,610 | | | 383,875 | | | Long-term notes receivable from associated companies | | | 7,546 | | | 97,489 | | | Other | | | 15,945 | | | 17,001 | | | | | | 989,273 | | | 1,095,010 | | CURRENT ASSETS: | | | | | | | | | Cash and cash equivalents | | | 207 | | | 197 | | | Receivables- | | | | | | | | | Customers (less accumulated provision of $4,510,000 for uncollectible accounts in 2005) | | | 255,422 | | | 11,537 | | | Associated companies | | | 29,279 | | | 33,414 | | | Other (less accumulated provisions of $19,000 and $293,000, respectively, | | | | | | | | | for uncollectible accounts) | | | 11,109 | | | 152,785 | | | Notes receivable from associated companies | | | 23,537 | | | 521 | | | Materials and supplies, at average cost | | | 87,713 | | | 58,922 | | | Prepayments and other | | | 1,948 | | | 2,136 | | | | | | 409,215 | | | 259,512 | | DEFERRED CHARGES: | | | | | | | | | Goodwill | | | 1,693,629 | | | 1,693,629 | | | Regulatory assets | | | 902,137 | | | 958,986 | | | Property taxes | | | 77,792 | | | 77,792 | | | Other | | | 36,471 | | | 32,875 | | | | | | 2,710,029 | | | 2,763,282 | | | | | $ | 6,689,750 | | $ | 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 | | $ | 1,356,983 | | $ | 1,281,962 | | | Accumulated other comprehensive income | | | 16,212 | | | 17,859 | | | Retained earnings | | | 480,957 | | | 553,740 | | | Total common stockholder's equity | | | 1,854,152 | | | 1,853,561 | | | Preferred stock | | | - | | | 96,404 | | | Long-term debt and other long-term obligations | | | 1,948,083 | | | 1,970,117 | | | | | | 3,802,235 | | | 3,920,082 | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | | 75,694 | | | 76,701 | | | Short-term borrowings- | | | | | | | | | Associated companies | | | 404,290 | | | 488,633 | | | Other | | | 155,000 | | | - | | | Accounts payable- | | | | | | | | | Associated companies | | | 191,959 | | | 150,141 | | | Other | | | 5,733 | | | 9,271 | | | Accrued taxes | | | 122,675 | | | 129,454 | | | Accrued interest | | | 21,782 | | | 22,102 | | | Lease market valuation liability | | | 60,200 | | | 60,200 | | | Other | | | 43,841 | | | 61,131 | | | | | | 1,081,174 | | | 997,633 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 543,554 | | | 540,211 | | | Accumulated deferred investment tax credits | | | 58,241 | | | 60,901 | | | Asset retirement obligation | | | 281,206 | | | 272,123 | | | Retirement benefits | | | 84,428 | | | 82,306 | | | Lease market valuation liability | | | 638,100 | | | 668,200 | | | Other | | | 200,812 | | | 149,009 | | | | | | 1,806,341 | | | 1,772,750 | | COMMITMENTS AND CONTINGENCIES (Note 13) | | | | | | | | | | | $ | 6,689,750 | | $ | 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) | | | | | | June 30, | | | December 31, | | | | | 2006 | | | 2005 | | | | | (In thousands) | | ASSETS | | | | | | | | CURRENT ASSETS: | | | | | | | | | Cash and cash equivalents | | $ | 217 | | $ | 207 | | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $5,836,000 and $5,180,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 273,324 | | | 268,427 | | | Associated companies | | | 37,168 | | | 86,564 | | | Other | | | 14,703 | | | 16,466 | | | Notes receivable from associated companies | | | 29,048 | | | 19,378 | | | Prepayments and other | | | 1,504 | | | 1,903 | | | | | | 355,964 | | | 392,945 | | UTILITY PLANT: | | | | | | | | | In service | | | 2,063,137 | | | 2,030,935 | | | Less - Accumulated provision for depreciation | | | 800,356 | | | 788,967 | | | | | | 1,262,781 | | | 1,241,968 | | | Construction work in progress | | | 73,869 | | | 51,129 | | | | | | 1,336,650 | | | 1,293,097 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Long-term notes receivable from associated companies | | | 940,786 | | | 1,057,337 | | | Investment in lessor notes | | | 519,615 | | | 564,166 | | | Other | | | 13,710 | | | 12,840 | | | | | | 1,474,111 | | | 1,634,343 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 1,688,521 | | | 1,688,966 | | | Regulatory assets | | | 858,618 | | | 862,193 | | | Prepaid pension costs | | | 137,082 | | | 139,012 | | | Property taxes | | | 63,500 | | | 63,500 | | | Other | | | 33,130 | | | 27,614 | | | | | | 2,780,851 | | | 2,781,285 | | | | | $ | 5,947,576 | | $ | 6,101,670 | | LIABILITIES AND CAPITALIZATION | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 543 | | $ | 75,718 | | | Short-term borrowings- | | | | | | | | | Associated companies | | | 154,731 | | | 212,256 | | | Other | | | 149,000 | | | 140,000 | | | Accounts payable- | | | | | | | | | Associated companies | | | 65,148 | | | 74,993 | | | Other | | | 8,121 | | | 4,664 | | | Accrued taxes | | | 119,555 | | | 121,487 | | | Accrued interest | | | 18,810 | | | 18,886 | | | Lease market valuation liability | | | 60,200 | | | 60,200 | | | Other | | | 39,512 | | | 61,308 | | | | | | 615,620 | | | 769,512 | | | | | | | | | | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity- | | | | | | | | | Common stock, without par value, authorized 105,000,000 shares - | | | | | | | | | 79,590,689 shares outstanding | | | 1,355,926 | | | 1,354,924 | | | Retained earnings | | | 687,615 | | | 587,150 | | | Total common stockholder's equity | | | 2,043,541 | | | 1,942,074 | | | Long-term debt and other long-term obligations | | | 1,886,636 | | | 1,939,300 | | | | | | 3,930,177 | | | 3,881,374 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 551,553 | | | 554,828 | | | Accumulated deferred investment tax credits | | | 22,093 | | | 23,908 | | | Lease market valuation liability | | | 577,900 | | | 608,000 | | | Retirement benefits | | | 83,604 | | | 83,414 | | | Deferred revenues - electric service programs | | | 63,566 | | | 71,261 | | | Other | | | 103,063 | | | 109,373 | | | | | | 1,401,779 | | | 1,450,784 | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | $ | 5,947,576 | | $ | 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 | THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | CONSOLIDATED STATEMENTS OF CASH FLOWS | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | (Unaudited) | | (Unaudited) | | | | | | | | | | | | | | Six Months Ended | | | | | Three Months Ended | | Six Months Ended | | | June 30, | | | | | June 30, | | June 30, | | | 2006 | | | 2005 | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | (In thousands) | | | | | (In thousands) | | | | | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | | | | | | | Net income | | $ | 38,669 | | $ | 49,725 | | $ | 54,141 | | $ | 98,200 | | $ | 163,465 | | $ | 54,141 | | | Adjustments to reconcile net income to net cash from | | | | | | | | | | | | | | | | operating activities - | | | | | | | | | | | | | | | | Adjustments to reconcile net income to net cash from operating activities - | | | | | | | | | Provision for depreciation | | | 33,387 | | | 32,776 | | | 64,502 | | | 64,964 | | | 28,251 | | | 64,502 | | | Amortization of regulatory assets | | | 55,016 | | | 50,022 | | | 109,042 | | | 98,090 | | | 61,006 | | | 109,042 | | | Deferral of new regulatory assets | | | (40,701 | ) | | (32,956 | ) | | (65,989 | ) | | (51,436 | ) | | (62,223 | ) | | (65,989 | ) | | Nuclear fuel and capital lease amortization | | | 6,171 | | | 7,509 | | | 10,781 | | | 12,616 | | | 120 | | | 10,781 | | | Amortization of electric service obligation | | | (4,672 | ) | | (4,818 | ) | | (10,123 | ) | | (9,541 | ) | | | Deferred rents and lease market valuation liability | | | (222 | ) | | (223 | ) | | (53,691 | ) | | (41,858 | ) | | (55,043 | ) | | (53,691 | ) | | Deferred income taxes and investment tax credits, net | | | 8,956 | | | 2,412 | | | 4,450 | | | (1,627 | ) | | (4,745 | ) | | 4,450 | | | Accrued retirement benefit obligations | | | 2,600 | | | 2,314 | | | 2,122 | | | 8,046 | | | | Accrued compensation, net | | | 230 | | | 476 | | | (2,495 | ) | | 1,929 | | | | Accrued compensation and retirement benefits | | | 1,584 | | | (373 | ) | | Decrease (increase) in operating assets- | | | | | | | | | | | | | | | | | | | | | Receivables | | | (182,964 | ) | | (33,923 | ) | | (98,074 | ) | | 109,843 | | | 46,262 | | | (98,074 | ) | | Materials and supplies | | | (6,455 | ) | | (3,118 | ) | | (28,791 | ) | | (5,473 | ) | | - | | | (28,791 | ) | | Prepayments and other current assets | | | (439 | ) | | 2 | | | 188 | | | 1,897 | | | 399 | | | 188 | | | Increase (decrease) in operating liabilities- | | | | | | | | | | | | | | | | | | | | | Accounts payable | | | (958 | ) | | (80,735 | ) | | 38,280 | | | (58,348 | ) | | (6,388 | ) | | 38,280 | | | Accrued taxes | | | 14,419 | | | 31,061 | | | (6,779 | ) | | (36,865 | ) | | (1,932 | ) | | (6,779 | ) | | Accrued interest | | | (12,351 | ) | | (7,392 | ) | | (320 | ) | | 847 | | | (76 | ) | | (320 | ) | | Prepayment for electric service - education programs | | | 67,589 | | | - | | | 67,589 | | | - | | | | Electric service prepayment programs | | | (7,695 | ) | | 57,466 | | | Other | | | (4,513 | ) | | (7,070 | ) | | (7,871 | ) | | (36,858 | ) | | (4,162 | ) | | (7,871 | ) | | Net cash provided from (used for) operating activities | | | (26,238 | ) | | 6,062 | | | 76,962 | | | 154,426 | | | | Net cash provided from operating activities | | | 158,823 | | | 76,962 | | | | | | | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | New Financing- | | | | | | | | | | | | | | | | | | | | | Long-term debt | | | 53,284 | | | - | | | 53,284 | | | 80,908 | | | - | | | 53,284 | | | Short-term borrowings, net | | | 88,557 | | | 101,255 | | | 58,874 | | | - | | | - | | | 58,874 | | | Equity contributions from parent | | | 75,000 | | | - | | | 75,000 | | | - | | | - | | | 75,000 | | | Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | | Preferred stock | | | (4,000 | ) | | - | | | (101,900 | ) | | - | | | - | | | (101,900 | ) | | Long-term debt | | | (56,600 | ) | | (175 | ) | | (56,930 | ) | | (8,101 | ) | | (118,152 | ) | | (56,930 | ) | | Short-term borrowings, net | | | - | | | - | | | - | | | (80,912 | ) | | (57,675 | ) | | - | | | Dividend Payments- | | | | | | | | | | | | | | | | | | | | | Common stock | | | (69,000 | ) | | (90,000 | ) | | (124,000 | ) | | (145,000 | ) | | (63,000 | ) | | (124,000 | ) | | Preferred stock | | | - | | | (1,754 | ) | | (2,260 | ) | | (3,498 | ) | | - | | | (2,260 | ) | | Net cash provided from (used for) financing activities | | | 87,241 | | | 9,326 | | | (97,932 | ) | | (156,603 | ) | | | Net cash used for financing activities | | | (238,827 | ) | | (97,932 | ) | | | | | | | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | Property additions | | | (26,561 | ) | | (20,861 | ) | | (60,244 | ) | | (38,729 | ) | | (65,551 | ) | | (60,244 | ) | | Loan repayments from (loans to) associated companies, net | | | (23,861 | ) | | 13,736 | | | 66,927 | | | 10,814 | | | | Loan repayments from associated companies, net | | | 108,169 | | | 66,927 | | | Investments in lessor notes | | | 3 | | | - | | | 32,473 | | | 20,965 | | | 44,551 | | | 32,473 | | | Contributions to nuclear decommissioning trusts | | | (7,256 | ) | | (7,256 | ) | | (14,512 | ) | | (14,512 | ) | | | Proceeds from nuclear decommissioning trust fund sales | | | - | | | 198,974 | | | Investments in nuclear decommissioning trust funds | | | - | | | (213,486 | ) | | Other | | | (3,328 | ) | | (1,007 | ) | | (3,664 | ) | | (943 | ) | | (7,155 | ) | | (3,664 | ) | | Net cash provided from (used for) investing activities | | | (61,003 | ) | | (15,388 | ) | | 20,980 | | | (22,405 | ) | | | Net cash provided from investing activities | | | 80,014 | | | 20,980 | | | | | | | | | | | | | | | | | | | | | | | | Net increase (decrease) in cash and cash equivalents | | | - | | | - | | | 10 | | | (24,582 | ) | | | Net increase in cash and cash equivalents | | | 10 | | | 10 | | | Cash and cash equivalents at beginning of period | | | 207 | | | 200 | | | 197 | | | 24,782 | | | 207 | | | 197 | | | Cash and cash equivalents at end of period | | $ | 207 | | $ | 200 | | $ | 207 | | $ | 200 | | $ | 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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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. | | |
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 June 30, 2005,2006, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2006 and 2005 and 2004.the consolidated statement of cash flows for the six-month period ended June 30, 2006 and 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 have 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[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)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 July 29, 2005August 4, 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 In 2005, the Ohio Companies and Penn 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 CEI’s leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates. 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 comparative earnings 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 leasehold 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 second quarter and first six months of 2006 compared to the same periods 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 | Income Statement Effects | | Three Months | | | Six Months | | Increase (Decrease) | | (In millions) | | | Revenues: | | | | | | | | Non-nuclear generating units rent | (a) | $ | (14 | ) | | $ | (29 | ) | | Nuclear generated KWH sales | (b) | | (57 | ) | | | (110 | ) | | Total - Revenues Effect | | | (71 | ) | | | (139 | ) | | Expenses: | | | | | | | | | | Fuel costs - nuclear | (c) | | (8 | ) | | | (14 | ) | | Nuclear operating costs | (c) | | (37 | ) | | | (95 | ) | | Provision for depreciation | (d) | | (13 | ) | | | (32 | ) | | General taxes | (e) | | (4 | ) | | | (8 | ) | | Total - Expenses Effect | | | (62 | ) | | | (149 | ) | | Operating Income Effect | | | (9 | ) | | | 10 | | | Other Income: | | | | | | | | | | Interest income from notes receivable | (f) | | 14 | | | | 30 | | | Nuclear decommissioning trust earnings | (g) | | (2 | ) | | | (4 | ) | | Capitalized interest | (h) | | (1 | ) | | | - | | | Total - Other Income Effect | | | 11 | | | | 26 | | | Income taxes | (i) | | 1 | | | | 15 | | | Net Income Effect | | $ | 1 | | | $ | 21 | | | | | | | | | | | | | (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 second quarter of 2005 decreased2006 increased to $91 million from $39 million from $48 million in the second quarter of 2005. For the first six months of 2005, earnings on common stock decreased to $51 million from $95 million in the same period of 2004. The decrease in earnings in both 2005 periods primarily resulted from increases in nuclear operating costs, purchased power costs, regulatory asset amortization and a one-time income tax charge, which were partially offset by higher operating revenues, increased regulatory asset deferrals and lower net interest charges.
Operating revenues increased by $8 million or 1.8% in the second quarter of 2005 from the same period in 2004. Higher revenues for the quarter primarily resulted from increases in retail generation and distribution revenues of $4 million and $10 million, respectively, partially offset by a $3 million decrease in revenues from wholesale sales. During the first six months of 2005 compared to the same period in 2004, operating revenues increased by $15 million or 1.7%. Higher revenues for the first half of 2005 were due to increases in retail generation and distribution revenues of $10 million and $5 million, respectively, partially offset by a $3 million reduction in revenues from wholesale sales.
Increased retail generation revenues for the second quarter and first six months of 2005 resulted from higher commercial and industrial unit prices, and higher residential KWH sales, partially offset by lower industrial KWH sales. A 16.8% increase in residential KWH sales during the second quarter was primarily due to warmer weather in CEI's service area, as compared to last year. A decrease in residential customer shopping by 4.1 percentage points in the second quarter and 2.1 percentage points in the first six months of 2005 also contributed to the higher generation KWH sales for each period as compared to 2004.
Revenue from wholesale sales decreased by $3 million during the second quarter of 2005, reflecting the effect of a 7.5% net decrease in KWH sales. Under its Ohio transition plan, CEI is required to provide MSG to non-affiliated alternative suppliers (see Outlook - Regulatory Matters). Sales to FES decreased by $12 million (10.6% KWH decrease) due to a decrease in nuclear generation available for sale. The decrease in sales to FES was partially offset by a $9 million increase in MSG sales to non-affiliated wholesale customers (29.7% KWH increase) during the second quarter of 2005. In the first six months of 2005, wholesale sales revenue decreased by $32006, earnings on common stock increased to $163 million reflectingfrom $51 million in the effectsame period of a 5.4% net decrease2005. The increase in KWH sales. A decreaseearnings in sales to FES of $20 million (8.9% KWH decrease) wasboth 2006 periods resulted primarily from lower expenses and increased other income, partially offset by a $17lower revenues. These changes reflected the effects of the generation asset transfer shown in the table above and the absence of the $2 million increase (33.9% KWH increase)Davis-Besse fine in MSG sales to non-affiliated wholesale customers.
Revenues from distribution throughput increased $10the first quarter of 2005 and the $8 million impact of the Ohio tax change implementation in the second quarter of 2005 compared with the same quarter of 2004. The increase was due to higher residential and commercial revenues ($132005.
Revenues
Revenues decreased by $16 million and $3 million, respectively), reflecting increased distribution deliveriesor 3.6% in the second quarter of 2005,2006 from the same period in part2005. Excluding the effects of the generation asset transfers displayed above, revenues increased $55 million due to warmer weather. These increases werea $105 million increase in retail generation sales revenues and a $28 million reduction in customer shopping incentives, partially offset by lower industriala $62 million decrease in distribution revenues of $6and a $19 million as a result of lower unit prices and decreasesdecrease in KWHMSG wholesale sales.
Revenues from distribution throughput increased $5 million in In the first six months of 2006 compared to the same period in 2005, revenues decreased by $42 million or 4.7%. Excluding the effects of the generation asset transfers discussed above, revenues increased $97 million due to a $193 million increase in retail generation sales revenues and a $47 million reduction in customer shopping incentives, partially offset by a $106 million decrease in distribution revenues and a $37 million decrease in MSG wholesale sales.
Non-affiliated wholesale sales revenues decreased by $19 million for the second quarter of 2006 and $37 million for the first six months of 2006 compared with the same periodperiods in 20042005 due to higher revenuesthe cessation of the MSG sales arrangements under CEI’s transition plan in December 2005. CEI had been required to provide the residential ($9 million) and commercial ($5 million) sectors, partially offset by lower industrial revenues ($9 million). Higher distribution deliveries in the residential and commercial sectors were partially offset by lower unit prices and decreases in KWH sales in the industrial sector.MSG to non-affiliated alternative suppliers.
Changes in electric generation KWH sales and distribution deliveriesrevenues in the second quarter and first six months of 20052006 from the corresponding periods of 20042005 are summarized in the following table:table.
| | | Three | | Six | | Changes in KWH Sales | | Months | | Months | | Increase (Decrease) | | | | | | | Electric Generation: | | | | | | | Retail | | | (0.9 | )% | | (0.8 | )% | | Wholesale | | | (7.5 | )% | | (5.4 | )% | Total Electric Generation Sales | | | (4.8 | )% | | (3.4 | )% | | | | | | | | | | | Distribution Deliveries: | | | | | | | | | Residential | | | 16.8 | % | | 5.0 | % | | Commercial | | | 3.1 | % | | 4.3 | % | | Industrial | | | (3.4 | )% | | (2.9 | )% | Total Distribution Deliveries | | | 3.0 | % | | 1.0 | % | | | | | | | | | |
Changes in Generation KWH Sales | | Three Months | | Six Months | | Increase (Decrease) | | | | | | | Electric Generation: | | | | | | | Retail | | | 50.7 | % | | 48.5 | % | | Wholesale | | | (74.0) | % | | (71.4) | % | Net Decrease in Generation Sales | | | (21.4) | % | | (17.7) | % |
Changes in Generation Revenues | | | Three Months | | | Six Months | | Increase (Decrease) | | | (In millions) | | | Retail Generation: | | | | | | | | | Residential | | $ | 39 | | $ | 77 | | | Commercial | | | 38 | | | 70 | | | Industrial | | | 28 | | | 46 | | | Total Retail Generation | | | 105 | | | 193 | | | Wholesale* | | | (19 | ) | | (37 | ) | Net Increase in Generation Revenues | | $ | 86 | | $ | 156 | |
*Excludes impact of generation asset transfers related to nuclear generated KWH sales.
Increased retail generation revenue as shown in the table above for the second quarter 2006 compared with the same quarter of 2005 was due to increased KWH sales and higher unit prices. The higher unit prices for generation reflected the rate stabilization charge that became effective in the first quarter of 2006 under provisions of the RSP and RCP. The increase in generation KWH sales resulted from decreased customer shopping. Generation services provided by alternative suppliers as a percent of total sales delivered in CEI's service area decreased by: residential - 61.0 percentage points, commercial - 43.5 percentage points and industrial - 8.9 percentage points. The decreased shopping resulted from certain alternative energy suppliers terminating their supply arrangements with CEI's shopping customers in the fourth quarter of 2005.
Increased retail generation revenues in the first six months of 2006 compared with the same period in 2005 were also due to increased KWH sales and the higher unit prices under provisions of the RSP and RCP. The increase in generation KWH sales reflected a similar decrease in customer shopping as discussed above. This resulted in similar percentage decreases in the first half of 2006 in generation services provided by alternative suppliers as a percentage of total sales deliveries in CEI's service area (residential - 60.0 percentage points, commercial - 41.1 percentage points and industrial - 7.6 percentage points).
Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2006 from the corresponding periods of 2005 are summarized in the following table.
Changes in Distribution KWH Sales | | Three Months | | Six Months | | Increase (Decrease) | | | | | | | Distribution Deliveries: | | | | | | | | | Residential | | | (5.6) | % | | (3.8) | % | | Commercial | | | (2.7) | % | | (4.3) | % | | Industrial | | | (1.5) | % | | (2.6) | % | Net Decrease in Distribution Deliveries | | | (2.8) | % | | (3.3) | % |
Changes in Distribution Revenues | | Three Months | | Six Months | Increase (Decrease) | | (In millions) | | Residential | | $ | (16 | ) | $ | (21 | ) | | Commercial | | | (23 | ) | | (45 | ) | | Industrial | | | (23 | ) | | (40 | ) | Net Decrease in Distribution Revenues | | $ | (62 | ) | $ | (106 | ) |
Lower distribution revenues as shown in the table above in the second quarter and first six months of 2006 primarily reflected lower unit prices and decreased 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 increased transmission rates to recover 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 second quarter and first six months of 2006, compared to the same periods of 2005.
Under the Ohio transition plan, CEI had provided incentives to customers to encourage switching to alternative energy providers, reducing CEI's revenues. These revenue reductions, which were deferred for future recovery and did not affect earnings, ceased in 2006, resulting in a $28 million revenue increase for the second quarter of 2006 and a $47 million increase for the first six months of 2006 compared to the same periods of 2005, as discussed above.
Operating Expenses and Taxes
Total operating expenses and taxes increaseddecreased by $27$76 million in the second quarter and $61$174 million in the first six months of 20052006 from the same periods 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:
| | | | | | | | | | | Three | | Six | | | Operating Expenses and Taxes - Changes | | Months | | Months | | | Expenses - Changes | | | Three Months | | Six Months | | Increase (Decrease) | | (In millions) | | | (In millions) | | | Fuel costs | | $ | 2 | | $ | 3 | | | $ | - | | $ | 1 | | | Purchased power costs | | | 2 | | 10 | | | | 19 | | | 20 | | | Nuclear operating costs | | | 18 | | 44 | | | | Other operating costs | | | (5 | ) | | (5 | ) | | | (6 | ) | | 3 | | | Provision for depreciation | | | 1 | | - | | | | (9 | ) | | (4 | ) | | Amortization of regulatory assets | | | 5 | | 11 | | | | (26 | ) | | (48 | ) | | Deferral of new regulatory assets | | | (8 | ) | | (15 | ) | | | 9 | | | 4 | | | General taxes | | | 2 | | | 2 | | | | (1 | ) | | (1 | ) | | Income taxes | | | 10 | | | 11 | | | Net increase in operating expenses and taxes | | $ | 27 | | $ | 61 | | | | | | | | | | | | Net decrease in expenses | | | $ | (14 | ) | $ | (25 | ) |
Higher purchased power costs in the second quarter and in the first six months of 2005,2006 compared with the same periods in 2005 primarily reflected increases in KWH purchased to meet higher retail generation sales requirements. These increases were partially offset by the impact of lower unit prices associated with the new power supply agreement with FES and purchased power lease credit amortizations of $8 million and $16 million in the second quarter and the first six months of 2006, respectively. 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 operating 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. Lower other operating costs in the second quarter of 2004,2006 compared with the same period in 2005 reflected higher unit costs, partially offset by lower KWH purchased.the absence in 2006 of transmission expenses related to the 2005 competitive retail energy supplier reimbursements which were discontinued at the end of 2005. Higher purchased powerother operating costs in the first six months of 20052006 compared towith the same period last year reflected both higher unit costs and higher KWH purchased. The increase in nuclear operating costs2005 reflect increased transmission expenses, primarily related to MISO Day 2 operations that began on April 1, 2005.
Excluding the effects of the generation asset transfers, the decrease in depreciation in the second quarter and first six months of 2005,2006 compared towith the same periods of 2004,2005 was primarily dueattributable to a refueling outage (including an unplanned extension) atsecond quarter 2006 pretax credit adjustment of $6.5 million ($4 million net of tax) applicable to prior periods. Lower amortization of regulatory assets in both periods of 2006 reflected the Perry Plant and a refueling outage at Beaver Valley Unit 2. A mid-cycle inspection outage atcompletion of generation-related transition cost amortization under CEI’s transition plan, partially offset by the Davis-Besse Plantamortization of deferred MISO costs that are being recovered in the first quarter2006. The decreased deferral of 2005 also contributed to higher nuclear operating costs in the first six months of 2005. There were no scheduled outages in the first six months of 2004.
Highernew regulatory asset amortizationassets in the second quarter and first six months of 2006 compared with the same periods in 2005 was primarily due to the termination of the shopping incentive deferrals ($28 million and $47 million, respectively) and lower deferred MISO costs ($6 million and $5 million, respectively), partially offset by the deferrals of distribution costs ($14 million and $29 million, respectively) and fuel costs ($11 million and $19 million, respectively) under the RCP.
Other Income
The increase in other income of $14 million in the second quarter and $32 million in the first six months of 2006 compared towith the same periods last year was primarily due to interest income on associated company notes receivable from the generation asset transfers discussed above. Excluding the effects of the asset transfer, other income increased amortization of transition costs being recovered under the Rate Stabilization Plan. Increases in regulatory asset deferrals for both the second quarter and first six months of 2006 by $2 million and $7 million, respectively. The increase in 2005 as comparedboth periods was primarily due to the same periods in 2004 resulted from higher shopping incentive deferrals and related interest, and the PUCO-approved MISO cost deferrals, including interest, beginninga $6 million benefit recognized in the second quarter of 2006 related to the sale of the Ashtabula C Plant, partially offset by increased interest expense in 2006 in both periods due to the absence of financing cost reductions recognized in 2005 (see Outlook - Regulatory Matters).related to refinancing activities.
On June 30, 2005,Income Taxes
Increased income taxes in the Statesecond quarter and in the first six months of Ohio enacted new2006 compared with the same periods last year were primarily due to an increase in taxable income, partially offset by a reduction in the tax legislation that creates a new Commercial Activity Tax (CAT), which is based on qualifying "taxable gross receipts" and will not consider any expenses or costs incurredrates due to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax is effective July 1, 2005, and replaces the continuing phase-out of the income-based Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out overabsence of a five-year period at a rate of 20% annually, beginning with the year ended 2005, and personal property tax is phased-out over a four-year period at a rate of 25% annually, beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The impact on income taxes associated with the required adjustment to net deferred taxes for the second quarter of 2005 was additional tax expenseaddition to income taxes of approximately $8 million, which was partially offset byfrom the phase-outimplementation of the Ohio income tax which reduced income taxes by approximately $1 million in the second quarter of 2005. See Note 12 to the consolidated financial statements.legislation.
Net Interest ChargesPreferred Stock Dividend Requirements
Net interest charges continued to trend lower, decreasingPreferred stock dividend requirements decreased by $8 million in the second quarter and $10$3 million in the first six months of 2005 from2006, compared to the same periodsperiod last year reflectingas a result of the effectsoptional redemption of redemptions and refinancings of $286 million and $100 million, respectively, since July 1, 2004.CEI's remaining outstanding preferred stock in 2005.
Capital Resources and Liquidity
CEI’s During 2006, CEI expects to meet its contractual obligations with cash requirements in 2005 for operating expenses, construction expendituresfrom operations and scheduled debt maturities are expected to be met without increasing net debt.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 June 30, 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 second quarter and first six months of 2005,2006, compared with the corresponding periods in 2004,same period last year, were as follows:
| | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | Operating Cash Flows | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In millions) | | | | | | | | | | | | | Cash earnings (*) | | $ | 100 | | $ | 107 | | $ | 113 | | $ | 179 | | | Working capital and other | | | (126 | ) | | (101 | ) | | (36 | ) | | (25 | ) | | Total cash flows form operating activities | | $ | (26 | ) | $ | 6 | | $ | 77 | | $ | 154 | | | | | | | | | | | | | | | | | (*) Cash earnings is a non-GAAP measure (see reconciliation below). | | | | | | | | | | | | | |
| | | Six Months Ended June 30, | | Operating Cash Flows | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | Cash earnings * | | $ | 125 | | $ | 113 | | | Working capital and other | | | 34 | | | (36 | ) | | Net cash provided from operating activities | | $ | 159 | | $ | 77 | |
* 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 | | Six Months Ended | | | Six Months Ended | | | | | June 30, | | June 30, | | | June 30, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | (In millions) | | | | | | | | | | | | | | | Net income (GAAP) | | $ | 39 | | $ | 50 | | $ | 54 | | $ | 98 | | | | Net Income (GAAP) | | | $ | 163 | | $ | 54 | | | Non-cash charges (credits): | | | | | | | | | | | | | | | | | | | | | | Provision for depreciation | | | 34 | | | 33 | | | 65 | | | 65 | | | | 28 | | | 65 | | | Amortization of regulatory assets | | | 55 | | | 50 | | | 109 | | | 98 | | | | 61 | | | 109 | | | Deferral of new regulatory assets | | | (41 | ) | | (33 | ) | | (66 | ) | | (51 | ) | | | (62 | ) | | (66 | ) | | Nuclear fuel and capital lease amortization | | | 7 | | | 8 | | | 11 | | | 13 | | | | - | | | 11 | | | Amortization of electric service obligation | | | (5 | ) | | (6 | ) | | (10 | ) | | (10 | ) | | | (7 | ) | | (10 | ) | | Deferred rents and lease market valuation liability | | | (1 | ) | | - | | | (54 | ) | | (42 | ) | | | (55 | ) | | (54 | ) | | Deferred income taxes and investment tax credits, net | | | 9 | | | 2 | | | 5 | | | (2 | ) | | | (5 | ) | | 5 | | | Accrued retirement benefit obligations | | | 3 | | | 2 | | | 2 | | | 8 | | | | Accrued compensation, net | | | - | | | 1 | | | (3 | ) | | 2 | | | Accrued compensation and retirement benefits | | | | 2 | | | (1 | ) | | Cash earnings (Non-GAAP) | | $ | 100 | | $ | 107 | | $ | 113 | | $ | 179 | | | $ | 125 | | $ | 113 | | | | | | | | | | | | | | | | | |
The decrease inNet cash earnings of $7provided from operating activities increased by $82 million for the second quarter and $66 million forin the first six months of 2005,2006 from the same period last year as compared to the respective periodsa result of 2004, area $12 million increase in cash earnings described above under "Results of Operations". and a $70 million increase from working capital and other cash flows. The largest factors contributing to the changes in working capital and other operating cash flows for the second quarter and first six months of 20052006 are increaseschanges in accounts receivable related to the 2005 conversion of the CFC receivables financing ($155 million) to on-balance sheet transactions, offset in part by changes in accounts payable and the absence of funds received in 2005 for prepaid electric service under the Energy for Education Program and changes in accounts payable.Program.
Cash Flows from Financing Activities
Net cash provided from financing activities increased $78 million in the second quarter of 2005 from the second quarter of 2004. The increase resulted from a $75 million equity contribution from FirstEnergy and lower common stock dividends to FirstEnergy of $21 million, partially offset by a $20 million increase in net debt redemptions.
Net cash used for financing activities decreased $59increased by $141 million in the first six months of 20052006 from the same period last year. The decreaseincrease in funds used for financing activities primarily resulted from a $129 million increase in net preferred stock and debt redemptions and the absence of a $75 million equity contribution from FirstEnergy in the second quarter of 2005, lower common stock dividends to FirstEnergy and an increase in short-term financing, partially offset by an increasea $61 million decrease in preferredcommon stock redemptions.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 $559$304 million of short-term indebtedness as of June 30, 2005.2006. CEI has obtained authorization from the PUCO to incur short-term debt of up to $500 million (including the bank facility and utility money pool described below). As of June 30, 2006, CEI had the capability to issue $1.3 billion$247 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 $570$576 million as of June 30, 2005.2006. CEI has no restrictions on the issuance of preferred stock.
On April 20, 2005, Beaver County Industrial Development Authority pollution control bonds aggregating $53.9 million were refunded by CEI. The new bonds were issued inCFC is a Dutch Auction interest rate mode, insured with municipal bond insurance andwholly owned subsidiary of CEI whose borrowings are secured by FMB.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 June 30, 2006, the facility was drawn for $149 million.
On May 1, 2005, CEI redeemed $1.7 million of 7.00% Series B and Series C Pollution Control Revenue Bonds. The bonds were redeemed at par, plus accrued interest to the date of redemption. On June 6, 2005, CEI redeemed all 40,000 outstanding shares of $7.35 Series C preferred stock at $101.00 per share, plus accrued interest to the date of redemption.
On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. 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 termination date, as the same may be extended. CEI’s borrowing limit under the facility is $250 million.
On July 1, 2005, Ohio Air Quality Development Authority, Ohio Water Development Authority and Beaver County Industrial Development Authority pollution control bonds aggregating $2.9 million, $40.9 million and $45.15 million, respectively, were refunded by CEI. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance. CEI provided FMB collateral to the bond insurer.
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 second quarterfirst six months of 20052006 was 2.93%4.86%. 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 or 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 June 30, 2006, CEI's debt to total capitalization as defined under the revolving credit facility was 49%. 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 positive.
On May 16, 2005, S&P affirmed its 'BBB-' corporate creditstable. The ratings outlook from Moody's and Fitch on FirstEnergy and its units and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmation and outlook revision reflects the successful restart of the three nuclear units from their respective outages that occurred during the first half of 2005. S&P noted that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projected and its nuclear operations further stabilize.
On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in its outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.all securities is positive.
IIn 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 $117.8 million of pollution control notes having variable interest rates.
Cash Flows from Investing Activities
In the second quarter of 2005, net cash used for investing activities increased $46 million from the second quarter of 2004. The increase in funds used for investing activities primarily reflected increased property additions and an increase in loans to associated companies. The $43 million increase in netNet cash provided from investing activities forincreased by $59 million in the first six months of 2005 as compared to2006 from the same period last yearyear. The change was primarily due to increases inincreased loan payments receivedrepayments from associated companies partially offset by increased property additions.and the absence of net investments in nuclear decommissioning trust funds due to the intra-system nuclear generation asset transfer.
DuringCEI’s capital spending for the secondlast half of 2005, capital requirements for property additions are2006 is expected to be about $68 million, including $4 million for nuclear fuel.approximately $58 million. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. CEI has no additional requirements for sinking fund requirements for preferred stock and debt during the remainder of 2005.
CEI’s capital spending for the period 2005-20072006-2010 is expected to be about $368approximately $620 million (excluding nuclear fuel) of which approximately $118$127 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $79 million, of which about $13 million applies to 2005. During the same periods, CEI’s nuclear fuel investments are expected to be reduced by approximately $91 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 June 30, 2005,2006, the present value of these operating lease commitments, net of trust investments, total $101$98 million.
CEI sells substantially all of its retail customer receivables to CFC, its wholly owned subsidiary. As of June 16, 2005, the CFC receivables financing structure was renewed and restructured from an off-balance sheet transaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the balance sheet as short-term debt.
Equity Price Risk
Included in CEI’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $254 million and $242 million as of June 30, 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 June 30, 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.
FirstEnergy Intra-System Generation Asset Transfers
On May 18, 2005, OE, CEI and TE, entered into the agreements described below (Agreements) implementing a series of intra-system generation asset transfers. When concluded, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies in FirstEnergy’s nuclear, fossil and hydroelectric plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include leasehold interests of CEI, TE and OE in plants that are currently subject to sale and leaseback arrangements with non-affiliates.
These transactions are being undertaken in connection with the Ohio Companies’ restructuring plans that were approved by the PUCO. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. FENOC, a subsidiary of FirstEnergy, currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a master facility lease, leases the non-nuclear generation assets to be transferred and operates and maintains those assets. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.
As contemplated by the Agreements, CEI intends to transfer its interests in the nuclear generation assets to NGC through a sale at net book value. FGCO intends to exercise a purchase option under the Master Lease to acquire CEI’s non-nuclear generation assets at the values approved in the Ohio Transition Case.
Consummation of the transactions contemplated by each of the Agreements is subject to receipt of all necessary regulatory authorizations and other consents and approvals. FirstEnergy currently expects to complete the various asset transfers in the second half of 2005.
Regulatory Matters Regulatory assets are costs which have been authorized by the PUCO and the FERC 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 regulatory assets are expected to be recovered under the provisions of CEI’s transition plan. CEI’s regulatory assets as of June 30, 2006 and December 31, 2005, were $859 million and $862 million, respectively.
In 2001,On October 21, 2003 the Ohio customer rates were restructuredCompanies filed their 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 separate charges for transmission, distribution, transition cost recoverygeneration service rates beginning January 1, 2006, in response to the PUCO’s concerns about price 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, 2008 unless the PUCO accepts future competitive bid results prior tosupply uncertainty following the end of that period under the revised Rate Stabilization Plan. As part of CEI'sOhio Companies' 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 (MSG) 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 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 economicmarket development efforts. Onperiod. In 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 the proceeding as well as the associated entries on rehearing. Other key componentsOn September 28, 2005, the Supreme Court of Ohio heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order with respect to the approval of the Rate Stabilization Plan includerate stabilization charge, approval of the following:shopping credits, the granting of interest on shopping credit incentive deferral amounts, and approval of the Ohio Companies’ financial separation plan. It remanded one matter back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient means for customer participation in the competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion for Reconsideration with the Supreme Court of Ohio which was denied by the Court on June 21, 2006. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation, requesting the PUCO to initiate a proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. Separately, the OCC and NOAC also submitted to the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket to address the Court’s concern.
The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. 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. |
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 | | $ | 95 | | | 2007 | | | 113 | | | 2008 | | | 130 | | | 2009 | | | 211 | | | 2010 | | | 266 | | Total Amortization | | $ | 815 | |
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. 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:
| | · | Amortization period for transition costs being recovered through the RTC for CEI extends to as late as mid-2009;Recognize fuel and distribution deferrals commencing January 1, 2006; |
| | | | | · | Deferral of interest costsRecognize distribution deferrals on a monthly basis prior to review by the accumulated customer shopping incentives as new regulatory assets; andPUCO Staff; |
| | | | | · | AbilityClarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and | | | | | · | Clarify that distribution expenditures do not have to request increasesbe “accelerated” in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.order to be deferred. |
On May 27, 2005, CEI filed an application withThe 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 establish a generation rate adjustment rider undersimply accepting the Rate Stabilization Plan. The application seeks to implement recovery of increased fuel costs fromamounts contained in the Ohio Companies’ Motion. On February 3, 2006, through 2008 applicable to CEI’s retail customers through a tariff rider to be implementedseveral other parties filed applications for rehearing on the PUCO's January 1, 2006. The application reflects projected increases in fuel costs in4, 2006 compared to 2002 baseline costs. The new rider is seeking to recover all costs above the baseline. Various parties including the OCC have intervened in this case.Order. The Ohio Companies have received discovery requests fromresponded to the OCC and the PUCO staff. A procedural schedule has been establishedapplications for rehearing on February 8, 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 notices of appeal with a hearing scheduled for October 4, 2005.
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 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. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approvedSupreme Court of Ohio alleging various errors made by the PUCO for CEI in 2004. Any acceptance of future competitive bid results would terminateits order approving the Rate Stabilization Plan pricing, but notRCP. The Ohio Companies’ Motion to Intervene in the related approved accounting, and not until twelve months afterappeals was granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO authorizes such termination.and the Ohio Companies. The Appellees’ Merit Briefs are due on August 4, 2006. Appellants’ Reply Briefs will then be due on August 24, 2006.
On December 30, 2004, CEI filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seekssought recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $16 million per year; however, CEI anticipates that this amount will increase. CEIThe Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted thereafter each July 1. CEI1 thereafter. The parties reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, whichagreement that was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by CEI, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. If the settlement stipulation is approved by the PUCO the actual amounts to beon August 31, 2005. The incremental transmission and ancillary service revenues recovered through thefrom January 1 through June 30, 2006 rider will be submittedwere approximately $23.5 million. That amount included the recovery of a portion of the 2005 deferred MISO expenses as described below. On May 1, 2006, CEI filed a modification to the PUCO on or before November 1, 2005.rider to determine revenues ($51 million) from July 2006 through June 2007.
The second application seekssought 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 the MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Deferral of allPermission to defer costs incurred prior to December 31,30, 2004 was denied. The PUCO also authorized CEI to accrue carrying charges on the deferred balances. An application filed withOn August 31, 2005, the PUCO to recover theseOCC appealed the PUCO's decision. On January 20, 2006, the OCC sought rehearing of the PUCO’s approval of the recovery of deferred charges over a five-year periodcosts through the rider beginning in 2006, is pending. The OCC, OPAE and CEI each filed applications for rehearing. CEI sought authority to defer the transmission and ancillary service related costs incurred during the period OctoberJanuary 1, 20032006 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, theJune 30, 2006. The PUCO denied CEI's and OCC’s applications and, at the request of CEI, struck as untimely OPAE’s application. CEI andOCC's application on February 6, 2006. On March 23, 2006, the OCC have sixty days from that dateappealed the PUCO's order to file a notice of appeal with the Ohio Supreme Court. 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 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 arguments were heard on May 10, 2006. CEI is unable to predict when a decision may be issued. 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 CBP results in a lower price for retail customers.
On September 16, 2004,December 29, 2005, the FERC issued an order that imposedsetting the two power sales agreements for hearing. The order criticized the Ohio CBP, and required FES to submit additional obligationsevidence in support of the reasonableness of the prices charged in the power sales agreements. A pre-hearing conference was held on CEI under certain pre-Open Access transmission contracts among CEIJanuary 18, 2006 to determine the hearing schedule in this case. Under the procedural schedule, approved in this case, FES expected an initial decision to be issued in late January 2007. However, on July 14, 2006, the Chief Judge granted the joint motion of FES and the cities of Cleveland and Painesville, Ohio. UnderTrial Staff to appoint a settlement judge in this proceeding. The procedural schedule has been suspended pending negotiations among the FERC's original decision, CEI would have been responsible for a portion of new energy market charges imposed by MISO when its energy markets began 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, which became effective April 1, 2005. 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, without such authorization, would have been charged to income when incurred. CEI's regulatory assets as of June 30, 2005 and December 2004 were $0.9 billion and $1.0 billion, respectively. CEI is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $354 million as of June 30, 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.parties.
See Note 1411 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.
Environmental Matters
CEI accrues environmental liabilities 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.
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.
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.
Regulation of Hazardous WasteWaste-
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 June 30, 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$2 million as of June 30, 2005.2006.
See Note 13(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, 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 websiteWeb site (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. FirstEnergy is also is proceeding with the implementation of the 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 new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, thatequipment. The 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,
FirstEnergy companies also are defending six separate complaint cases before the PUCO is continuingrelating to review FirstEnergy’s 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. Three substantially similar actions were filed in various Ohio State courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All threeoutage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. Two ofIn these cases were refiled at the PUCO, one in 2004 and another in 2005. In each, individual complainants—three in one case and four in the other—seek damages related to the outages and also seeksought to represent others as part of a class action. FirstEnergy has filed responsive pleadings to both cases. The PUCO has dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. BothThree other pending PUCO complaint cases are otherwise currently pending further proceedings. In addition to the two cases that were refiled at the PUCO, the Ohio Companies were namedfiled by various insurance carriers either in their own name 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 was filed on August 25, 2004 against FirstEnergysubrogees or in the New York State Supreme Court.name of their insured. In thiseach of these three cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, several plaintiffs in the New York City metropolitan area allege that they sufferedfrom 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 power outages. None of the plaintiffs2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy affiliate.company. The sixth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It is currently expected that this case will be summarily dismissed, although the Motion is still pending. 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 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. 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 that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed an amended complaint and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. These motions are pending. Additionally, on June 23, 2006, one of the insurance carrier complainants filed an appeal with the Ohio Supreme Court on October 22, 2004. No timetableover the PUCO’s denial of their motion for a decisionrehearing on the motionissue of the admissibility of the Task Force Report and the dismissal of FirstEnergy Corp. as a respondent. Briefing is expected to dismiss has been establishedbe completed on this appeal by mid-September. It is unknown when the Court.Supreme Court will rule on the appeal. No damage estimate has been provided and thusof potential liability has not been determined.is available for any of these cases.
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.
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. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.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. On July 8, 2005, FENOC requested an additional 120 days to respond to the NOV. CEI has accrued the remaining liability for its share of the proposed fine of $1.8 million during the first quarter of 2005.below.
If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability based on the events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.
Effective July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to emergency sirens.
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 preceding two years. FENOC operates the Perry Nuclear Power Plant, which is currently owned and/or leased by OE, CEI, TE and Penn (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which will include owned portions of the plant). 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. On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. 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 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 now repealed 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 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.
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. Both filings were consolidated for hearing and decision described above. 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. On May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s complaint and approving the related tariffs, thus affirming OE’s entitlement to recovery of its transition charges. The City of Huron filed an application for rehearing of the PUCO’s decision on June 9, 2006 and OE filed a memorandum in opposition to that application on June 19, 2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The City of Huron has 60 days from the denial of rehearing to appeal the PUCO’s decision. 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 13(C)10 (C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.
New Accounting Standards and Interpretations
| SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"
|
In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. FirstEnergy will adopt this Statement effective January 1, 2006.
FIN 47, "Accounting48 - “Accounting for Conditional Asset Retirement ObligationsUncertainty in Income Taxes - an interpretation of FASB Statement No. 143"
On March 30, 2005, the FASB issued FIN 47 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 second 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. Therefore, FirstEnergy will adopt this Interpretation in the fourth quarter of 2005. FirstEnergy is currently evaluating the effect this Interpretation will have on its financial statements.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"109.”
In March 2004,June 2006, the EITF reached a consensus onFASB issued FIN 48 which clarifies the application guidanceaccounting for Issue 03-1. EITF 03-1 provides a model for determining when investmentsuncertainty 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 lossincome taxes recognized in earnings. Thean enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement provisions of EITF 03-1, which werea tax position taken or expected to be taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation will be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit to recognize in the financial statements. This interpretation is effective for periodsfiscal years beginning after JuneDecember 15, 2004, were delayed indefinitely by2006. CEI is currently evaluating the issuanceimpact of FSP EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy continues to evaluate its investments as required by existing authoritative guidance.this Statement.
THE TOLEDO EDISON COMPANY | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2006 | | 2005 | | 2006 | | 2005 | | STATEMENTS OF INCOME | | (In thousands) | | | | | | | | | | | | | REVENUES | | $ | 225,598 | | $ | 259,109 | | $ | 443,575 | | $ | 500,864 | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | Fuel | | | 9,638 | | | 14,404 | | | 19,400 | | | 26,973 | | | Purchased power | | | 80,659 | | | 72,300 | | | 156,079 | | | 152,456 | | | Nuclear operating costs | | | 17,866 | | | 46,689 | | | 35,198 | | | 105,852 | | | Other operating costs | | | 39,718 | | | 41,311 | | | 80,143 | | | 75,659 | | | Provision for depreciation | | | 8,240 | | | 15,209 | | | 16,337 | | | 29,889 | | | Amortization of regulatory assets | | | 22,117 | | | 33,231 | | | 46,573 | | | 68,096 | | | Deferral of new regulatory assets | | | (14,190 | ) | | (12,670 | ) | | (27,846 | ) | | (22,094 | ) | | General taxes | | | 12,253 | | | 13,620 | | | 25,184 | | | 27,801 | | | Total expenses | | | 176,301 | | | 224,094 | | | 351,068 | | | 464,632 | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 49,297 | | | 35,015 | | | 92,507 | | | 36,232 | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | Investment income | | | 8,945 | | | 8,188 | | | 18,725 | | | 17,072 | | | Miscellaneous expense | | | (1,926 | ) | | (3,100 | ) | | (4,610 | ) | | (6,402 | ) | | Interest expense | | | (4,364 | ) | | (2,941 | ) | | (8,674 | ) | | (9,977 | ) | | Capitalized interest | | | 344 | | | 188 | | | 558 | | | (255 | ) | | Total other income | | | 2,999 | | | 2,335 | | | 5,999 | | | 438 | | | | | | | | | | | | | | | | | INCOME TAXES | | | 19,924 | | | 29,674 | | | 37,128 | | | 28,629 | | | | | | | | | | | | | | | | | NET INCOME | | | 32,372 | | | 7,676 | | | 61,378 | | | 8,041 | | | | | | | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | 1,161 | | | 2,211 | | | 2,436 | | | 4,422 | | | | | | | | | | | | | | | | | EARNINGS ON COMMON STOCK | | $ | 31,211 | | $ | 5,465 | | $ | 58,942 | | $ | 3,619 | | | | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 32,372 | | $ | 7,676 | | $ | 61,378 | | $ | 8,041 | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | Unrealized gain (loss) on available for sale securities | | | 191 | | | (501 | ) | | (947 | ) | | (2,184 | ) | | Income tax expense (benefit) related to other | | | | | | | | | | | | | | | comprehensive income | | | 69 | | | (96 | ) | | (342 | ) | | (791 | ) | | Other comprehensive income (loss), net of tax | | | 122 | | | (405 | ) | | (605 | ) | | (1,393 | ) | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 32,494 | | $ | 7,271 | | $ | 60,773 | | $ | 6,648 | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements. |
THE TOLEDO EDISON COMPANY | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In thousands) | | STATEMENTS OF INCOME | | | | | | | | | | | | | | | | | | | | | OPERATING REVENUES | | $ | 259,109 | | $ | 243,366 | | $ | 500,864 | | $ | 478,764 | | | | | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | Fuel | | | 14,404 | | | 13,073 | | | 26,973 | | | 23,287 | | | Purchased power | | | 72,300 | | | 74,687 | | | 152,456 | | | 157,095 | | | Nuclear operating costs | | | 46,689 | | | 36,166 | | | 105,852 | | | 78,858 | | | Other operating costs | | | 41,311 | | | 41,155 | | | 75,659 | | | 77,363 | | | Provision for depreciation | | | 15,209 | | | 14,380 | | | 29,889 | | | 28,433 | | | Amortization of regulatory assets | | | 33,231 | | | 27,362 | | | 68,096 | | | 61,028 | | | Deferral of new regulatory assets | | | (12,670 | ) | | (10,192 | ) | | (22,094 | ) | | (17,222 | ) | | General taxes | | | 13,620 | | | 12,028 | | | 27,801 | | | 26,328 | | | Income taxes | | | 27,817 | | | 8,080 | | | 23,849 | | | 6,502 | | | Total operating expenses and taxes | | | 251,911 | | | 216,739 | | | 488,481 | | | 441,672 | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 7,198 | | | 26,627 | | | 12,383 | | | 37,092 | | | | | | | | | | | | | | | | | OTHER INCOME (net of income taxes) | | | 3,231 | | | 4,719 | | | 5,890 | | | 10,552 | | | | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | | | | Interest on long-term debt | | | 4,523 | | | 9,581 | | | 8,743 | | | 19,042 | | | Allowance for borrowed funds used during construction | | | (188 | ) | | (702 | ) | | 255 | | | (2,102 | ) | | Other interest expense | | | (1,582 | ) | | 889 | | | 1,234 | | | 1,595 | | | Net interest charges | | | 2,753 | | | 9,768 | | | 10,232 | | | 18,535 | | | | | | | | | | | | | | | | | NET INCOME | | | 7,676 | | | 21,578 | | | 8,041 | | | 29,109 | | | | | | | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | 2,211 | | | 2,211 | | | 4,422 | | | 4,422 | | | | | | | | | | | | | | | | | EARNINGS ON COMMON STOCK | | $ | 5,465 | | $ | 19,367 | | $ | 3,619 | | $ | 24,687 | | | | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 7,676 | | $ | 21,578 | | $ | 8,041 | | $ | 29,109 | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | Unrealized loss on available for sale securities | | | (501 | ) | | (6,974 | ) | | (2,184 | ) | | (1,292 | ) | | Income tax benefit related to other comprehensive income | | | 96 | | | 2,861 | | | 791 | | | 530 | | | Other comprehensive income (loss), net of tax | | | (405 | ) | | (4,113 | ) | | (1,393 | ) | | (762 | ) | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 7,271 | | $ | 17,465 | | $ | 6,648 | | $ | 28,347 | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of | | | | these statements. | | | | | | | | | | | | | |
THE TOLEDO EDISON COMPANY | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | June 30, | | December 31, | | | | | 2006 | | 2005 | | | | | (In thousands) | | ASSETS | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 23 | | $ | 15 | | | Receivables- | | | | | | | | | Customers | | | 782 | | | 2,209 | | | Associated companies | | | 39,407 | | | 16,311 | | | Other | | | 2,998 | | | 6,410 | | | Notes receivable from associated companies | | | 45,747 | | | 48,349 | | | Prepayments and other | | | 5,135 | | | 1,059 | | | | | | 94,092 | | | 74,353 | | UTILITY PLANT: | | | | | | | | | In service | | | 852,572 | | | 824,677 | | | Less - Accumulated provision for depreciation | | | 380,234 | | | 372,845 | | | | | | 472,338 | | | 451,832 | | | Construction work in progress | | | 28,499 | | | 33,920 | | | | | | 500,837 | | | 485,752 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Long-term notes receivable from associated companies | | | 382,733 | | | 436,178 | | | Investment in lessor notes | | | 169,493 | | | 178,798 | | | Nuclear plant decommissioning trusts | | | 59,126 | | | 59,209 | | | Other | | | 1,843 | | | 1,781 | | | | | | 613,195 | | | 675,966 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 500,576 | | | 501,022 | | | Regulatory assets | | | 267,032 | | | 287,095 | | | Prepaid pension costs | | | 35,124 | | | 35,566 | | | Property taxes | | | 18,047 | | | 18,047 | | | Other | | | 39,728 | | | 24,164 | | | | | | 860,507 | | | 865,894 | | | | | $ | 2,068,631 | | $ | 2,101,965 | | LIABILITIES AND CAPITALIZATION | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | - | | $ | 53,650 | | | Accounts payable- | | | | | | | | | Associated companies | | | 30,571 | | | 46,386 | | | Other | | | 4,256 | | | 2,672 | | | Notes payable to associated companies | | | 136,571 | | | 64,689 | | | Accrued taxes | | | 53,092 | | | 49,344 | | | Lease market valuation liability | | | 24,600 | | | 24,600 | | | Other | | | 19,379 | | | 40,049 | | | | | | 268,469 | | | 281,390 | | 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 | | | 473,908 | | | 473,638 | | | Accumulated other comprehensive income | | | 4,085 | | | 4,690 | | | Retained earnings | | | 223,370 | | | 189,428 | | | Total common stockholder's equity | | | 897,033 | | | 863,426 | | | Preferred stock | | | 66,000 | | | 96,000 | | | Long-term debt | | | 237,691 | | | 237,753 | | | | | | 1,200,724 | | | 1,197,179 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 209,389 | | | 221,149 | | | Accumulated deferred investment tax credits | | | 11,419 | | | 11,824 | | | Lease market valuation liability | | | 231,100 | | | 243,400 | | | Retirement benefits | | | 41,986 | | | 40,353 | | | Asset retirement obligation | | | 25,675 | | | 24,836 | | | Deferred revenues - electric service programs | | | 28,151 | | | 32,606 | | | Other | | | 51,718 | | | 49,228 | | | | | | 599,438 | | | 623,396 | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | $ | 2,068,631 | | $ | 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) | | | | | | | | Six Months Ended | | | | | June 30, | | | | | 2006 | | 2005 | | | | | (In thousands) | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 61,378 | | $ | 8,041 | | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | Provision for depreciation | | | 16,337 | | | 29,889 | | | Amortization of regulatory assets | | | 46,573 | | | 68,096 | | | Deferral of new regulatory assets | | | (27,846 | ) | | (22,094 | ) | | Nuclear fuel and capital lease amortization | | | - | | | 8,134 | | | Deferred rents and lease market valuation liability | | | (45,843 | ) | | (44,466 | ) | | Deferred income taxes and investment tax credits, net | | | (13,322 | ) | | 8,193 | | | Accrued compensation and retirement benefits | | | 1,268 | | | 1,500 | | | Decrease (increase) in operating assets- | | | | | | | | | Receivables | | | (18,257 | ) | | 12,539 | | | Materials and supplies | | | - | | | (5,912 | ) | | Prepayments and other current assets | | | (4,076 | ) | | 408 | | | Increase (decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | (14,231 | ) | | (74,371 | ) | | Accrued taxes | | | 3,748 | | | 10,509 | | | Accrued interest | | | (222 | ) | | (196 | ) | | Electric service prepayment programs | | | (4,454 | ) | | 36,563 | | | Other | | | 3,326 | | | (8,588 | ) | | Net cash provided from operating activities | | | 4,379 | | | 28,245 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | - | | | 45,000 | | | Short-term borrowings, net | | | 71,882 | | | - | | | Redemptions and Repayments- | | | | | | | | | Preferred stock | | | (30,000 | ) | | - | | | Long-term debt | | | (53,650 | ) | | (46,933 | ) | | Short-term borrowings, net | | | - | | | (96,381 | ) | | Dividend Payments- | | | | | | | | | Common stock | | | (25,000 | ) | | (10,000 | ) | | Preferred stock | | | (2,436 | ) | | (4,422 | ) | | Net cash used for financing activities | | | (39,204 | ) | | (112,736 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (29,361 | ) | | (32,168 | ) | | Loan repayments from (loans to) associated companies, net | | | 2,611 | | | (4,001 | ) | | Collection of principal on long-term notes receivable | | | 53,766 | | | 123,546 | | | Investments in lessor notes | | | 9,305 | | | 11,895 | | | Proceeds from nuclear decommissioning trust fund sales | | | 30,665 | | | 153,940 | | | Investments in nuclear decommissioning trust funds | | | (30,754 | ) | | (168,211 | ) | | Other | | | (1,399 | ) | | (510 | ) | | Net cash provided from investing activities | | | 34,833 | | | 84,491 | | | | | | | | | | | | Net change in cash and cash equivalents | | | 8 | | | - | | | Cash and cash equivalents at beginning of period | | | 15 | | | 15 | | | Cash and cash equivalents at end of period | | $ | 23 | | $ | 15 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements. |
THE TOLEDO EDISON COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | June 30, | | December 31, | | | | | 2005 | | 2004 | | | | | (In thousands) | | ASSETS | | | | | | UTILITY PLANT: | | | | | | | In service | | $ | 1,902,930 | | $ | 1,856,478 | | | Less - Accumulated provision for depreciation | | | 802,653 | | | 778,864 | | | | | | 1,100,277 | | | 1,077,614 | | | Construction work in progress - | | | | | | | | | Electric plant | | | 52,465 | | | 58,535 | | | Nuclear fuel | | | 4,063 | | | 15,998 | | | | | | 56,528 | | | 74,533 | | | | | | 1,156,805 | | | 1,152,147 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Investment in lessor notes | | | 178,797 | | | 190,692 | | | Nuclear plant decommissioning trusts | | | 315,142 | | | 297,803 | | | Long-term notes receivable from associated companies | | | 40,014 | | | 39,975 | | | Other | | | 1,784 | | | 2,031 | | | | | | 535,737 | | | 530,501 | | CURRENT ASSETS: | | | | | | | | | Cash and cash equivalents | | | 15 | | | 15 | | | Receivables - | | | | | | | | | Customers (less accumulated provisions of $1,000 and $2,000, respectively, | | | | | | | | | for uncollectible accounts) | | | 2,105 | | | 4,858 | | | Associated companies | | | 19,373 | | | 36,570 | | | Other | | | 3,182 | | | 3,842 | | | Notes receivable from associated companies | | | 16,099 | | | 135,683 | | | Materials and supplies, at average cost | | | 46,192 | | | 40,280 | | | Prepayments and other | | | 742 | | | 1,150 | | | | | | 87,708 | | | 222,398 | | DEFERRED CHARGES: | | | | | | | | | Goodwill | | | 504,522 | | | 504,522 | | | Regulatory assets | | | 330,192 | | | 374,814 | | | Property taxes | | | 24,100 | | | 24,100 | | | Other | | | 39,189 | | | 25,424 | | | | | | 898,003 | | | 928,860 | | | | | $ | 2,678,253 | | $ | 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 | | | 428,566 | | | 428,559 | | | Accumulated other comprehensive income | | | 18,646 | | | 20,039 | | | Retained earnings | | | 184,678 | | | 191,059 | | | Total common stockholder's equity | | | 827,560 | | | 835,327 | | | Preferred stock | | | 126,000 | | | 126,000 | | | Long-term debt | | | 296,482 | | | 300,299 | | | | | | 1,250,042 | | | 1,261,626 | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | | 90,950 | | | 90,950 | | | Accounts payable - | | | | | | | | | Associated companies | | | 34,806 | | | 110,047 | | | Other | | | 3,117 | | | 2,247 | | | Notes payable to associated companies | | | 333,136 | | | 429,517 | | | Accrued taxes | | | 57,466 | | | 46,957 | | | Lease market valuation liability | | | 24,600 | | | 24,600 | | | Other | | | 25,802 | | | 53,055 | | | | | | 569,877 | | | 757,373 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 235,448 | | | 221,950 | | | Accumulated deferred investment tax credits | | | 24,024 | | | 25,102 | | | Retirement benefits | | | 41,464 | | | 39,227 | | | Asset retirement obligation | | | 200,867 | | | 194,315 | | | Lease market valuation liability | | | 255,700 | | | 268,000 | | | Other | | | 100,831 | | | 66,313 | | | | | | 858,334 | | | 814,907 | | COMMITMENTS AND CONTINGENCIES (Note 13) | | | | | | | | | | | $ | 2,678,253 | | $ | 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 STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In thousands) | | | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | Net income | | $ | 7,676 | | $ | 21,578 | | $ | 8,041 | | $ | 29,109 | | | Adjustments to reconcile net income to net cash from | | | | | | | | | | | | | | | operating activities - | | | | | | | | | | | | | | | Provision for depreciation | | | 15,209 | | | 14,380 | | | 29,889 | | | 28,433 | | | Amortization of regulatory assets | | | 33,231 | | | 27,362 | | | 68,096 | | | 61,028 | | | Deferral of new regulatory assets | | | (12,670 | ) | | (10,192 | ) | | (22,094 | ) | | (17,222 | ) | | Nuclear fuel and capital lease amortization | | | 3,266 | | | 5,032 | | | 8,134 | | | 10,538 | | | Amortization of electric service obligation | | | (1,391 | ) | | - | | | (1,391 | ) | | - | | | Deferred rents and lease market valuation liability | | | (29,242 | ) | | (28,582 | ) | | (44,466 | ) | | (36,274 | ) | | Deferred income taxes and investment tax credits, net | | | 9,580 | | | (2,651 | ) | | 8,193 | | | (4,682 | ) | | Accrued retirement benefit obligations | | | 1,626 | | | 1,124 | | | 2,237 | | | 3,409 | | | Accrued compensation, net | | | 528 | | | 1,694 | | | (737 | ) | | 961 | | | Decrease (increase) in operating assets - | | | | | | | | | | | | | | | Receivables | | | (28,936 | ) | | 5,440 | | | 12,539 | | | 25,475 | | | Materials and supplies | | | 577 | | | (2,217 | ) | | (5,912 | ) | | (3,651 | ) | | Prepayments and other current assets | | | 464 | | | 1,910 | | | 408 | | | 5,294 | | | Increase (decrease) in operating liabilities - | | | | | | | | | | | | | | | Accounts payable | | | (81,306 | ) | | (9,696 | ) | | (74,371 | ) | | (15,770 | ) | | Accrued taxes | | | 25,771 | | | 17,820 | | | 10,509 | | | 3,735 | | | Accrued interest | | | (1,049 | ) | | 1,910 | | | (196 | ) | | (371 | ) | | Prepayment for electric service -- education programs | | | 37,954 | | | - | | | 37,954 | | | - | | | Other | | | (6,618 | ) | | 8,488 | | | (8,607 | ) | | 341 | | | Net cash provided from (used for) operating activities | | | (25,330 | ) | | 53,400 | | | 28,226 | | | 90,353 | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | New Financing - | | | | | | | | | | | | | | | Long-term debt | | | 45,000 | | | - | | | 45,000 | | | 73,000 | | | Redemptions and Repayments - | | | | | | | | | | | | | | | Long-term debt | | | (46,933 | ) | | - | | | (46,933 | ) | | (15,000 | ) | | Short-term borrowings, net | | | (61,388 | ) | | (23,761 | ) | | (96,381 | ) | | (117,060 | ) | | Dividend Payments - | | | | | | | | | | | | | | | Common stock | | | (10,000 | ) | | - | | | (10,000 | ) | | - | | | Preferred stock | | | (2,211 | ) | | (2,211 | ) | | (4,422 | ) | | (4,422 | ) | | Net cash used for financing activities | | | (75,532 | ) | | (25,972 | ) | | (112,736 | ) | | (63,482 | ) | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | Property additions | | | (14,249 | ) | | (10,987 | ) | | (32,168 | ) | | (19,427 | ) | | Loan repayments from (loans to) associated companies, net | | | 121,155 | | | (3,263 | ) | | 119,545 | | | (657 | ) | | Investments in lessor notes | | | (33 | ) | | - | | | 11,895 | | | 10,280 | | | Contributions to nuclear decommissioning trusts | | | (7,136 | ) | | (7,136 | ) | | (14,271 | ) | | (14,271 | ) | | Other | | | 1,125 | | | (6,043 | ) | | (491 | ) | | (5,018 | ) | | Net cash provided from (used for) investing activities | | | 100,862 | | | (27,429 | ) | | 84,510 | | | (29,093 | ) | | | | | | | | | | | | | | | | | Net decrease in cash and cash equivalents | | | - | | | (1 | ) | | - | | | (2,222 | ) | | Cash and cash equivalents at beginning of period | | | 15 | | | 16 | | | 15 | | | 2,237 | | | Cash and cash equivalents at end of period | | $ | 15 | | $ | 15 | | $ | 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 subsidiarysubsidiaries as of June 30, 2005,2006, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2006 and 2005 and 2004.the consolidated statement of cash flows for the six-month period ended June 30, 2006 and 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 have 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[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)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 July 29, 2005August 4, 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
In 2005, the Ohio Companies and Penn 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 affect TE’s comparative earnings 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 leasehold interests in the Bruce Mansfield Plant and Beaver Valley Unit 2, TE has continued the generation KWH sales arrangement with FES and its Beaver Valley Unit 2 leased capacity sales arrangement with CEI, 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 second quarter and first six months of 2006 compared to the same periods of 2005 from the generation asset transfers are summarized in the following table:
Intra-System Generation Asset Transfers - | Income Statement Effects | | Three Months | | | Six Months | | Increase (Decrease) | | (In millions) | | | Revenues: | | | | | | | | Non-nuclear generating units rent | (a) | $ | (3 | ) | | $ | (7 | ) | | Nuclear generated KWH sales | (b) | | (29 | ) | | | (51 | ) | | Total - Revenues Effect | | | (32 | ) | | | (58 | ) | | Expenses: | | | | | | | | | | Fuel costs - nuclear | (c) | | (5 | ) | | | (8 | ) | | Nuclear operating costs | (c) | | (22 | ) | | | (62 | ) | | Provision for depreciation | (d) | | (7 | ) | | | (16 | ) | | General taxes | (e) | | (2 | ) | | | (3 | ) | | Total - Expenses Effect | | | (36 | ) | | | (89 | ) | | Operating Income Effect | | | 4 | | | | 31 | | | Other Income: | | | | | | | | | | Interest income from notes receivable | (f) | | 4 | | | | 8 | | | Nuclear decommissioning trust earnings | (g) | | (3 | ) | | | (4 | ) | | Capitalized interest | (h) | | (1 | ) | | | - | | | Total - Other Income Effect | | | - | | | | 4 | | | Income taxes | (i) | | 1 | | | | 14 | | | Net Income Effect | | $ | 3 | | | $ | 21 | | | | | | | | | | | | | (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 second quarter of 2005 decreased2006 increased to $5$31 million from earnings of $19$5 million in the second quarter of 2004.2005. This increase resulted primarily from reduced expenses and the absence of additional income taxes of $17.5 million from the implementation of Ohio tax legislation changes in the second quarter of 2005, partially offset by lower revenues. Earnings on common stock in the first six months of 2005 decreased2006 increased to $4$59 million from $25$4 million in the first six months of 2004. The decrease in earnings in both periods2005. This increase resulted primarily from reduced expenses, increased other income and the absence of 2005 resulted principally from higher nuclear operating costs and a one-timethe additional income tax charge,taxes discussed above, also partially offset by higher operating revenues and lower financing costs compared torevenues. The earnings increases for both periods included the same periodeffects of 2004.the generation asset transfer shown in the table above.
Operating revenues increasedRevenues
Revenues decreased by $16$33 million or 6.5%,12.9% in the second quarter of 2006 compared with the same period of 2005, primarily due to the generation asset transfer impact displayed in the table above. Excluding the effects of the generation asset transfers, revenues decreased $1 million due to decreased distribution revenues of $34 million, partially offset by a $23 million increase in generation sales revenues, a $9 million reduction in customer shopping incentives and a $1 million increase in other revenues.
In the first six months of 2006, revenues decreased by $57 million or 11.4% compared with the same period of 2005, primarily due to the generation asset transfer impact displayed in the table above. Excluding the effects of the generation asset transfers, revenues increased $1 million due to a $44 million increase in generation sales revenues, a $15 million reduction in customer shopping incentives and a $1 million increase in other revenues, partially offset by a $59 million decrease in distribution revenues.
Changes in electric generation KWH sales and revenues in the second quarter and first six months of 2006 from the corresponding periods of 2005 are summarized in the following table.
Changes in Generation KWH Sales | | Three Months | | Six Months | | Increase (Decrease) | | | | | | | Electric Generation: | | | | | | | Retail | | | 16.1 | % | | 12.8 | % | | Wholesale | | | (57.6 | )% | | (56.7 | )% | Net Decrease in Generation Sales | | | (24.5 | )% | | (23.8 | )% |
Changes in Generation Revenues | | Three Months | | Six Months | Increase (Decrease) | | (In millions) | | Retail Generation: | | | | | | | | | Residential | | $ | 17 | | $ | 32 | | | Commercial | | | 13 | | | 22 | | | Industrial | | | 7 | | | 9 | | | Total Retail Generation | | | 37 | | | 63 | | | Wholesale* | | | (14 | ) | | (19 | ) | Net Increase in Generation Revenues | | $ | 23 | | $ | 44 | |
* Excludes impact of generation asset transfers related to nuclear generated KWH sales.
Retail generation revenues increased in all customer sectors as shown in the table above in the second quarter of 2006 compared to the corresponding quarter of 2005 due to higher unit prices and increased KWH sales. The higher unit prices for generation reflected the rate stabilization charge and the fuel cost recovery rider that both became effective in the first quarter of 2006 under provisions of the RSP and RCP. The increase in generation KWH sales (residential - 52.5%, commercial - 15.5% and industrial - 7.1%) primarily resulted from decreased customer shopping. The decreased shopping resulted from certain alternative energy suppliers terminating their supply arrangements with TE's shopping customers in the first quarter of 2006. Generation services provided by alternative suppliers as a percentage of total sales delivered in TE's franchise area decreased in all customer classes by: residential - 34.4 percentage points, commercial - 11.4 percentage points and industrial - 2 percentage points.
In the first six months of 2006, retail generation revenues increased from the corresponding period of 2005 for the reasons described above. The decreased customer shopping resulted in generation KWH sales increases in all customer classes (residential - 44.1%, commercial - 13.6% and industrial - 3.8%). Similar to the second quarter of 2004. Higher2006, generation services provided by alternative suppliers as a percentage of total sales deliveries in TE's franchise area decreased in all customer classes by: residential - 29 percentage points, commercial - 10 percentage points and industrial - 1.7 percentage points.
Lower wholesale revenues in the second quarter and first six months of 2005 resulted2006 reflected decreased revenues from increased retail generation salesnon-affiliates ($5 million and $8 million, respectively) and decreased revenues offrom associated companies ($9 million and $11 million, distribution revenues of $4 million and wholesales sales (primarily to FES) of $2 million, partially offset by an increaserespectively). The non-affiliated wholesale revenue decreases in shopping incentive credits of $1 million. Retail generation sales revenues increased as a result of increased KWH sales (residential - $1 million, commercial - $2 million, industrial - $8 million). Higher residential and commercial revenues reflected increased KWH sales (24.5% and 23.2%, respectively), partially offset by lower unit prices. Residential and commercial sales volumes increased2006 were primarily due to warmer weatherthe cessation of the MSG sales arrangements under TE’s transition plan in TE’s service area.December 2005. TE had been required to provide the MSG to non-affiliated alternative suppliers. The commercial generation sales volume increase also reflects a reduction by 4.7 percentage pointslower wholesale revenues from associated companies in customer shopping compared with2006 reflected lower unit prices due to this year’s absence of expenses related to the second quarter of 2004. Industrial revenues increasedBeaver Valley Unit 2 nuclear refueling outage in April 2005, which were included as a resultcomponent of higher unit prices, partially offset by a 3.9% decrease in KWH sales.the associated company billing for the 2005 period.
Revenues fromChanges in distribution throughput increased by $4 millionKWH deliveries and revenues in the second quarter and first six months of 20052006 from the corresponding periods of 2005 are summarized in the following table.
Changes in Distribution KWH Deliveries | | Three Months | | Six Months | | Increase (Decrease) | | | | | | | Distribution Deliveries: | | | | | | | | | Residential | | | (6.6 | )% | | (3.8 | )% | | Commercial | | | (5.1 | )% | | (4.4 | )% | | Industrial | | | 4.9 | % | | 1.9 | % | Net Decrease in Distribution Deliveries | | | (0.5 | )% | | (1.2 | )% |
Changes in Distribution Revenues | | Three Months | | Six Months | Increase (Decrease) | | (In millions) | | Residential | | $ | (14 | ) | $ | (25 | ) | | Commercial | | | (16 | ) | | (29 | ) | | Industrial | | | (4 | ) | | (5 | ) | Net Decrease in Distribution Revenues | | $ | (34 | ) | $ | (59 | ) |
The distribution revenue decreases as shown in the table above in the second quarter and first six months of 2004. The increase was due2006 compared to higherthe same periods of 2005 primarily reflected lower unit prices in all customer sectors and decreased KWH deliveries to residential and commercial revenues ($9 million and $4 million, respectively)customers. The lower unit prices reflected the completion of the generation-related transition cost recovery under TE’s transition plan in 2005, partially offset by a decreaseincreased transmission rates to recover MISO costs beginning in industrial revenues ($9 million)the first quarter of 2006 (see Outlook - Regulatory Matters). The impact of higherlower KWH distribution deliveries to residential and commercial KWH sales contributed tocustomers in both periods reflected the increaseimpact of milder weather in the second quarter and offset the lower industrial sales volume and unit prices.
Operating revenues increased by $22 million, or 4.6% in the first six months of 20052006 compared to the same periodperiods of 2004. Higher revenues2005. KWH deliveries to industrial customers increased in the first six monthsboth periods of 2005 resulted primarily from increased retail generation sales revenues of $21 million and wholesales sales (primarily to FES) of $5 million, partially offset by a decrease in distribution revenues of $2 million. Retail generation sales revenues increased as result of higher KWH sales in all customer sectors (residential - $1 million, commercial - $3 million, industrial - $17 million). Increases in residential and commercial revenues reflected increased KWH sales (6.3% and 13.9%, respectively)2006 due to warmer weather, partially offset by lower unit prices. The higher industrial revenues resulted primarily from higher unit prices.
Revenues from distribution throughput decreased by $2 million in the first six months of 2005 compared to the same period in 2004 as a result of lower industrial KWH sales and reduced unit prices, which offset increases in KWHincreased sales to residentialautomotive, oil refinery and commercialsteel industry customers.
Under the Ohio transition plan, TE provideshad provided incentives to customers to encourage switching to alternative energy providers. TE’s revenues wereproviders which reduced by $1 million from additional credits in the second quarter and $2 million in the first six months of 2005 compared with the same periods of 2004.TE's revenues. These revenue reductions, arewhich were deferred for future recovery under TE’s transition plan and dodid not affect current period earnings, (see Regulatory Matters below).
Changesceased in electric generation sales and distribution deliveries2006 thereby increasing revenues in the second quarter and first six months of 2005 from2006 by $9 million and $15 million, respectively. The deferred shopping incentives (Extended RTC) are currently being recovered under the corresponding periods of 2004, are summarized in the following table:RCP (see Outlook - Regulatory Matters).
| | | Three | | Six | | Changes in KWH Sales | | Months | | Months | | Increase (Decrease) | | | | | | | Electric Generation: | | | | | | | Retail | | | 4.6 | % | | 2.8 | % | | Wholesale | | | (6.5 | )% | | 3.4 | % | Total Electric Generation Sales | | | (1.8 | )% | | 3.1 | % | | | | | | | | | | | Distribution Deliveries: | | | | | | | | | Residential | | | 25.5 | % | | 9.3 | % | | Commercial | | | 12.1 | % | | 8.0 | % | | Industrial | | | (3.1 | )% | | (0.6 | )% | Total Distribution Deliveries | | | 6.4 | % | | 3.9 | % | | | | | | | | | |
Operating Expenses and Taxes
Total operating expenses decreased by $48 million and taxes increased by $35$114 million in the second quarter and $47 million in the first six months of 20052006, respectively, from the same periods of 2005 principally due to the generation asset transfer effects as shown in 2004. Thethe table above. Excluding the asset transfer effects, the following table presents changes from the prior year by expense category.category:
| | | Three | | Six | | | Operating Expenses and Taxes - Changes | | Months | | Months | | | Expenses - Changes | | | Three Months | | Six Months | | Increase (Decrease) | | (In millions) | | | (In millions) | | | Fuel costs | | $ | 1 | | $ | 4 | | | | Fuel | | | $ | - | | $ | 1 | | | Purchased power costs | | | (2 | ) | | (5 | ) | | | 8 | | | 4 | | | Nuclear operating costs | | | 10 | | | 27 | | | | (6 | ) | | (9 | ) | | Other operating costs | | | - | | | (2 | ) | | | (1 | ) | | 4 | | | Provision for depreciation | | | 1 | | | 1 | | | | - | | | 2 | | | Amortization of regulatory assets | | | 6 | | | 7 | | | | (11 | ) | | (21 | ) | | Deferral of new regulatory assets | | | (3 | ) | | (5 | ) | | | (2 | ) | | (6 | ) | | General taxes | | | 2 | | | 2 | | | | Income taxes | | | 20 | | | 18 | | | Net increase in operating expenses and taxes | | $ | 35 | | $ | 47 | | | Net decrease in expenses | | | $ | (12 | ) | $ | (25 | ) | | | | | | | | | | | | | | | |
Higher fuelpurchased power costs in the second quarter of 2006 compared to the second quarter of 2005 primarily reflected an increase in KWH purchased to meet the higher retail generation sales requirements and higher unit prices associated with the new power supply agreement with FES. Decreased nuclear operating costs in the 2006 quarter were due to lower costs associated with TE’s leasehold interest in Beaver Valley Unit 2. The decrease reflected the absence in 2006 of expenses in the second quarter of 2005 related to Beaver Valley Unit 2’s 25-day nuclear refueling outage in April 2005.
Higher purchased power costs in the first six months of 2006 compared to the same period of 2005 reflected an increase in KWH purchased to meet higher retail generation sales requirements, partially offset by lower unit prices. The nuclear operating costs decrease in the first six months of 2006 was due to the reasons described above for the second quarter. Higher other operating costs reflect increased transmission expenses, primarily related to MISO Day 2 operations that began on April 1, 2005.
Excluding the effects of the generation asset transfers, depreciation charges in the first six months of 2006 increased due to distribution plant additions.
Lower amortization of regulatory assets in both periods of 2006 reflected the completion of generation-related transition cost recovery under TE’s transition plan, partially offset by the amortization of deferred MISO costs that are being recovered in 2006. The net change in deferrals of new regulatory assets in the second quarter and first six months of 2005, compared with2006 primarily resulted from the same periodsdeferrals of 2004, resulted principally from increased fossil generation — up 12.4%distribution costs ($7 million and 19.8%, respectively. Lower purchased power costs in both periods reflect lower unit costs and a reduction in KWH purchased$13 million in the second quarter of 2005. Nuclear operating costs increased in both periods due to a scheduled refueling outage (including an unplanned extension) at the Perry Plant, a mid-cycle inspection outage at the Davis-Besse Plant duringand the first quartersix months of 2005,2006, respectively) and the Beaver Valley Unit 2 refueling outageincremental fuel costs ($4 million and $7 million in the second quarter and the first six months of 2005. Other operating costs remained unchanged2006, respectively) that began in 2006 under the RCP, partially offset by the impact of the termination of shopping incentive deferrals in 2006 ($9 million and $16 million in the second quarter and the first six months of 20052006, respectively). Other Income
Other income increased $5 million in the first six months of 2006 compared to the same period of 2004. MISO Day 2 expenses that began2005, primarily due to the effects of the generation asset transfers. Excluding the asset transfer effects, the $1 million increase reflected lower net interest charges and the absence of a charge of $1.6 million for an NRC fine related to Davis-Besse Plant in the first quarter of 2005, partially offset by the absence of interest income on a note from FGCO, which had a balloon repayment in May 2005. Income Taxes
Income taxes decreased $10 million in the second quarter of 2005 were offset2006 and increased by decreased vegetation management expenses. Other operating costs decreased$8 million in the first six months of 20052006 compared to the same periodperiods of 2004 in part from lower employee benefits costs.
Depreciation charges increased by $1 million2005. Excluding the effects of the generation asset transfer, income taxes decreased in the second quarter and first six months of 2005 compared2006 by $11 million and $6 million, respectively. These decreases were primarily due to the same periodsabsence in 2006 of 2004 due to an increase$17.5 million of additional income tax expenses from the implementation of Ohio tax legislation changes in depreciable assets. This increase wasthe second quarter of 2005 and the subsequent reduction in the tax rates, partially offset by the effect of revised service life assumptions for fossil generating plants (See Note 3). Regulatory asset amortization increasedincreases in both periods due to the increased amortization of transition costs being recovered under the Rate Stabilization Plan. Deferrals of new regulatory assets increasedtaxable income.
Preferred Stock Dividend Requirements
Lower preferred stock dividend requirements in the second quarter and first six months of 20052006 compared to the samecorresponding 2005 periods of 2004, primarily due to higher shopping incentives and related interest ($1 million and $3 million, respectively) andwere the deferral of the PUCO-approved MISO administrative expenses and related interest ($1 million) that began in the second quarter of 2005.
On June 30, 2005, the State of Ohio enacted new tax legislation that creates a new Commercial Activity Tax (CAT), which is based on qualifying "taxable gross receipts" and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax is effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and personal property tax is phased-out over a four-year period at a rate of approximately 25%, annually beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as$60 million of June 30, 2005. The impact on income taxes associated with the required adjustment to net deferred taxes for the second quarter of 2005 was additional tax expense of approximately $18 million, which was partially offset by the phase-out of the Ohio income tax which reduced income taxes by approximately $1 million in the second quarter of 2005. See Note 12 to the consolidated financial statements.
Other Income
Other income decreased by $2 million in the second quarter of 2005 and $5 million in the first six months of 2005 from the same periods of 2004, primarily due to a decrease in earnings on nuclear decommissioning trust investments and the absence of interest income earned on associated company notes receivable that were repaid in May 2005. Additionally, the recognition of a $1.6 million proposed NRC fine related to the Davis-Besse Plant (see Outlook - Other Legal Proceedings) during the first quarter of 2005, caused other income to decrease during the first six months of 2005.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $7 million in the second quarter of 2005 and $8 million in the first six months of 2005 from the same periods of 2004, reflectingoptional preferred stock redemptions and refinancings subsequent to the end of the second 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 increasing its 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 $300 million of new long-term debt in 2006 with proceeds expected to fund a return of equity capital to FirstEnergy.
Changes in Cash Position
As of June 30, 2005, TE's2006, TE had $23,000 of cash and cash equivalents, ofcompared with $15,000 remained unchanged from itsas of December 31, 2004 balance.2005. The major changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided from operating activities during the second quarter andfirst six months of 2006, compared with the first six months of 2005, compared with the corresponding period of 2004 were as follows:
| | | Three Months Ended | | Six Months Ended | | | Six Months Ended | | | | | June 30, | | June 30, | | | June 30, | | Operating Cash Flows | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | (In millions) | | | | | | | | | | | | | | Cash earnings* | | $ | 28 | | $ | 30 | | $ | 56 | | $ | 75 | | | $ | 34 | | $ | 56 | | | Working capital and other | | | (53 | ) | | 23 | | | (28 | ) | | 15 | | | | (30 | ) | | (28 | ) | | Total cash flows form operating activities | | $ | (25 | ) | $ | 53 | | $ | 28 | | $ | 90 | | | | Net cash provided from operating activities | | | $ | 4 | | $ | 28 | | | | | | | | | | | | | | | | | | | | | | | | * Cash earnings are a non-GAAP measure (see reconciliation below). | | | | *Cash earnings are a non-GAAP measure (see reconciliation below). | | *Cash earnings are a non-GAAP measure (see reconciliation below). |
Cash earnings as disclosed in(in the table above,above) are not a measure of performance calculated in accordance with GAAP. 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 | | Six Months Ended | | | | | | June 30, | | June 30, | | | Six Months Ended June 30, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | (In millions) | | | | | | | | | | | | | | | Net income (GAAP) | | $ | 8 | | $ | 22 | | $ | 8 | | $ | 29 | | | | Non-cash charges (credits): | | | | | | | | | | | | | | | | Net Income (GAAP) | | | $ | 61 | | $ | 8 | | | Non-Cash Charges (Credits): | | | | | | | | | | Provision for depreciation | | | 15 | | | 14 | | | 30 | | | 29 | | | | 16 | | | 30 | | | Amortization of regulatory assets | | | 33 | | | 27 | | | 68 | | | 61 | | | | 47 | | | 68 | | | Deferral of new regulatory assets | | | (13 | ) | | (10 | ) | | (22 | ) | | (17 | ) | | | (28 | ) | | (22 | ) | | Nuclear fuel and capital lease amortization | | | 3 | | | 5 | | | 8 | | | 10 | | | | - | | | 8 | | | Amortization of electric service obligation | | | (1 | ) | | - | | | (1 | ) | | - | | | | (4 | ) | | (1 | ) | | Deferred rents and above-market lease liability | | | (29 | ) | | (28 | ) | | (44 | ) | | (36 | ) | | | Deferred rents and lease market valuation liability | | | | (46 | ) | | (44 | ) | | Deferred income taxes and investment tax credits, net | | | 10 | | | (3 | ) | | 8 | | | (5 | ) | | | (13 | ) | | 8 | | | Accrued retirement benefits obligations | | | 2 | | | 1 | | | 2 | | | 3 | | | | Accrued compensation, net | | | - | | | 2 | | | (1 | ) | | 1 | | | | Accrued compensation and retirement benefits | | | | 1 | | | 1 | | | Cash earnings (Non-GAAP) | | $ | 28 | | $ | 30 | | $ | 56 | | $ | 75 | | | $ | 34 | | $ | 56 | | | | | | | | | | | | | | | | | |
Net cash provided from operating activities decreased by $78$24 million in the second quarterfirst six months of 20052006 from the second quarterfirst six months of 20042005 as a result of a $76 million decrease in working capital and $2$22 million decrease in cash earnings described above under “Results of Operations” and under "Results of Operations". Net cash provideda $2 million decrease from operating activities decreased by $62 million in the first six months of 2005 compared to the same period last year as a result of a $43 millionworking capital and other changes. The decrease in working capital and other primarily resulted from the absence in 2006 of funds received in 2005 for a $19 million decreaseprepaid electric service program and a reduction in cash earnings described above and under "Resultsreceived from the settlement of Operations". The change in working capital for both periods was primarily due to changes in accounts payable and accounts receivable,receivables, partially offset by funds received for prepaid electric service under the Ohio Schools Council’s Energy for Education Program that began in the second quarter of 2005.lower cash payments on accounts payable.
Cash Flows From Financing Activities
Net cash used for financing activities increased by $50decreased to $39 million in the second quarter and first six months of 2005, as compared to2006 from $113 million in the same periodsperiod of 2004, and2005. The decrease resulted primarily from ana $168 million increase in net short-term borrowings, partially offset by an $82 million net increase in preferred stock and long-term debt redemptions in both periods. The increase was also due toand a $10$15 million increase in common stock dividendsdividend payments to FirstEnergy during the second quarter of 2005.in 2006.
TE had $16$46 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $333$137 million of short-term indebtedness as of June 30, 2005.2006. TE has authorization from the PUCO to incur short-term debt of up to $500 million (includingthrough the bank facility and utility money pool described below).below. As of June 30, 2005,2006, TE had the capability to issue $890$634 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 $950 million$1.1 billion of preferred stock (assuming no additional debtdebt) was issued as of June 30, 2005).2006.
On June 14, 2005, TE, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility.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 andor the commitment terminationexpiration date, as the same may be extended. TE'sTE’s borrowing limit under the facility is $250 million.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 June 30, 2006, TE's debt to total capitalization, as defined under the revolving credit facility, was 28%. 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 second quarterfirst six months of 20052006 was 2.93%4.86%.
On April 20, 2005, Beaver County Industrial Development Authority pollution control bonds aggregating $45 million were refunded by TE. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance and secured by FMB.112
On July 1, 2005, TE redeemed all of its 1.2 million outstanding shares of 7.00% Series A preferred stock at $25.00 per share, plus accrued dividends to the date of redemption.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. On May 16, 2005,The ratings outlook from S&P affirmed its 'BBB-' corporate crediton all securities is stable. The ratings outlook from Moody’s and Fitch on FirstEnergy and its units and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmation and outlook revision reflects the successful restart of the three nuclear units from their respective outages that occurred during the first half of 2005. S&P noted that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projected and its nuclear operations further stabilize.all securities is positive. On July 18, 2005, Moody’s revised its rating outlook on FirstEnergyIn April 2006, pollution control notes that were formerly obligations of TE were refinanced and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvementbecame obligations of FGCO and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemmingNGC. The proceeds from the applicationrefinancings were used to repay a portion of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continuestheir associated company notes payable to achieve planned improvementsTE. With those repayments, TE redeemed pollution control notes in its operations and balance sheet.the aggregate principal amount of $54 million having variable interest rates.
Cash Flows From Investing Activities
Net cash provided from investing activities increaseddecreased by $128 million in the second quarter and $114$50 million in the first six months of 2005,2006 from the same periodsperiod of 2004. These increases were2005 primarily due to higher loan repaymentsa decrease in the collection of principal on long-term notes receivable. This resulted from associated companies during the second quarterreceipt in April 2006 of $54 million from FGCO and NGC following the pollution control notes refinancing discussed above as compared to the receipt in May 2005 of a $123 million balloon payment from FGCO for gas-fired combustion turbines sold in 2001. This decrease in cash receipts was partially offset by increasedreduced property additions.additions and net activity for the nuclear decommissioning trust funds due to the generation asset transfers.
TE’s capital spending for the last two quartershalf of 20052006 is expected to be about $36 million (excluding $3 million for nuclear fuel).approximately $29 million. These cash requirements are expected to be satisfied from a combination of internal cash and short-term borrowings.
credit arrangements. TE’s capital spending for the period 2005-20072006-2010 is expected to be about $192approximately $232 million, (excluding nuclear fuel), of which approximately $56$58 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to total approximately $56 million, of which about $10 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 June 30, 2005,2006, the present value of these operating lease commitments, net of trust investments, totaled $531$498 million.
TE sells substantially all of its retail customer receivables to CFC, a wholly owned subsidiary of CEI. As of June 16, 2005, the CFC receivables financing structure was renewed and restructured from an off-balance sheet transaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the balance sheet as short-term debt.
Equity Price Risk
Included in TE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $199 million and $188 million as of June 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $20 million reduction in fair value as of June 30, 2005. Changes in the fair value of these investments are recorded in OCI unless recognized as a result of sales.
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.
FirstEnergy Intra-System Generation Asset Transfers
On May 18, 2005, OE, CEI and TE, entered into the agreements described below (Agreements) implementing a series of intra-system generation asset transfers. When concluded, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies in FirstEnergy’s nuclear, fossil and hydroelectric plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include leasehold interests of CEI, TE and OE in plants that are currently subject to sale and leaseback arrangements with non-affiliates.Regulatory Matters
Regulatory assets are costs which have been authorized by the PUCO and the FERC 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 regulatory assets are expected to be recovered under the provisions of TE’s regulatory plans. TE’s regulatory assets as of June 30, 2006 and December 31, 2005 were $267 million and $287 million, respectively.
These transactions are being undertaken in connectionOn October 21, 2003 the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the Ohio Companies’ restructuring plans that wereCompanies accepted the RSP as modified and approved by the PUCO under applicable Ohio electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies were required to be separated from the regulated delivery business of those companies through transferin an August 4, 2004 Entry on Rehearing, subject to a separate corporate entity. FENOC, a subsidiary of FirstEnergy, currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a master facility lease, leases the non-nuclear generation assets to be transferred and operates and maintains those assets.CBP. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.
As contemplated by the Agreements, TE intends to transfer its interests in the nuclear generation assets to NGC through a sale at net book value. FGCO intends to exercise a purchase option under the Master Lease to acquire TE’s non-nuclear generation assets at the values approved in the Ohio Transition case.
Consummation of the transactions contemplated by each of the Agreements is subject to receipt of all necessary regulatory authorizations and other consents and approvals. FirstEnergy currently expects to complete the various asset transfers in the second half of 2005.
Regulatory Matters
In 2001, Ohio customer rates were restructuredRSP was intended to establish separate charges for transmission, distribution, transition cost recoverygeneration service rates beginning January 1, 2006, in response to the PUCO’s concerns about price 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 unless the PUCO accepts future competitive bid results prior tosupply uncertainty following the end of that period under the revised Rate Stabilization Plan.
As part of TE'sOhio Companies' 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 (MSG) 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 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 economicmarket development efforts. Onperiod. In 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 the proceeding as well as the associated entries on rehearing. Other key componentsOn September 28, 2005, the Supreme Court of Ohio heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order with respect to the approval of the revised Rate Stabilization Plan includerate stabilization charge, approval of the following:shopping credits, the granting of interest on shopping credit incentive deferral amounts, and approval of the Ohio Companies’ financial separation plan. It remanded one matter back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient means for customer participation in the competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion for Reconsideration with the Supreme Court of Ohio which was denied by the Court on June 21, 2006. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation, requesting the PUCO to initiate a proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. Separately, the OCC and NOAC also submitted to the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket to address the Court’s concern.
The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. Major provisions of the RCP include:
| | | Amortization periodMaintaining the existing level of base distribution rates through December 31, 2008 for transition costs being recovered through the RTC extends to as late as mid-2008;TE; |
| | · | DeferralDeferring 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 interestthe three years; |
| | Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs onwill 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 customer shopping incentives as newcost of removal regulatory assets;liability; and |
| | | Ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases inRecovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and taxes.$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. |
On May 27, 2005, TE filed an application with the PUCO to establish a generation rate adjustment rider under its Rate Stabilization Plan. The application seeks to implement recoveryfollowing table provides TE’s estimated amortization of increased fuelregulatory transition costs from 2006 through 2008 applicable to TE’s retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider is seeking to recover all costs above the baseline. Various parties including the OCC have intervened in this case. TE has received discovery requests from the OCC and the PUCO staff. A procedural schedule has been established by the PUCO, with a hearing scheduled for October 4, 2005.
On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricingdeferred shopping incentives (including associated carrying charges) under the approved Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may require the Ohio Companies to undertake, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid processRCP for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for the Ohio Companies in 2004. 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.2006 through 2008:
Amortization Period | | Amortization | | | | | (In millions) | | | 2006 | | $ | 86 | | | 2007 | | | 90 | | | 2008 | | | 111 | | Total Amortization | | $ | 287 | |
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. 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. The Ohio Companies’ Motion to Intervene in the appeals was granted by the Supreme Court on June 8, 2006. The Appellant’s Merit Briefs were filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO and the Ohio Companies. The Appellees’ Merit Briefs are due on August 4, 2006. Appellent’s Reply Briefs will then be due in August 24, 2006. On December 30, 2004, TE filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seekssought recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $0.1 million per year; however, TE anticipates that this amount will increase. TE requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted thereafter each July 1. TE1 thereafter. The parties reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc. agreed not to oppose the settlement. This settlement, whichagreement that was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by TE, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. If the settlement stipulation is approved by the PUCO the actual amounts to beon August 31, 2005. The incremental transmission and ancillary service revenues recovered through thefrom January 1 through June 30, 2006 rider will be submittedwere approximately $6.5 million. That amount included the recovery of a portion of the 2005 deferred MISO expenses as described below. On May 1, 2006, TE filed a modification to the PUCO on or before November 1, 2005.rider to determine revenues ($19 million) from July 2006 through June 2007.
The second application seekssought 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 TEthe Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in the MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Deferral of allPermission to defer costs incurred prior to December 31,30, 2004 was denied. The PUCO also authorized TEthe Ohio Companies to accrue carrying charges on the deferred balances. An application filed withOn August 31, 2005, the OCC appealed the PUCO's decision. On January 20, 2006, the OCC sought rehearing of the PUCO to recover theseapproval of the recovery of deferred charges over a five-year periodcosts through the rider beginning in 2006, is pending. The OCC, OPAE and TE each filed applications for rehearing. TE sought authority to defer the transmission and ancillary service related costs incurred during the period OctoberJanuary 1, 20032006 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, theJune 30, 2006. The PUCO denied TE's and OCC’s applications and, at the request of TE, struck as untimely OPAE’s application. TE andOCC's application on February 6, 2006. On March 23, 2006, the OCC have sixty days from that dateappealed the PUCO's order to file a notice of appeal with the Ohio Supreme Court. 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 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 were heard on May 10, 2006. The Ohio Companies are unable to predict when a decision may be issued.
TE records as regulatory assets costs which have been authorized 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 CBP results in a lower price for retail customers.
On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticized the Ohio CBP, 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. Under upon the procedural schedule, approved in the case, FES expected an initial decision to be issued inin late January 2007. However, on July 14, 2006, the Chief Judge granted the joint motion of FES and the FERC for recovery from customersTrial Staff to appoint a settlement judge in future periods and, without such authorization, would havethis proceeding. The procedural schedule has been charged to income when incurred. TE's regulatory assets as of June 30, 2005 and December 31, 2004, were $330 million and $375 million, respectively. TE is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $108 million as of June 30, 2005 and will be recovered through a surcharge rate equal tosuspended pending negotiations among 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.parties.
See Note 1411 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.
Environmental Matters
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.
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.
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.
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 June 30, 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 June 30, 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 13(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, 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 websiteWeb site (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. FirstEnergy is also is proceeding with the implementation of the 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 new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, thatequipment. The 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 FirstEnergy’s 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.
Three substantially similar actions were filed in various Ohio State courts by plaintiffs seekingFirstEnergy companies also are defending six separate complaint cases before the PUCO relating to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All threeoutage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. Two ofIn these cases were refiled at the PUCO, one in 2004 and another in 2005. In each, individual complainants—three in one case and four in the other—seek damages related to the outages and also seeksought to represent others as part of a class action. FirstEnergy has filed responsive pleadings to both cases. The PUCO has dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. BothThree other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these three 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 otherwisenot customers of any FirstEnergy company. The sixth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It is currently pending further proceedings. In addition toexpected that this case will be summarily dismissed, although the two cases that were refiled atMotion is still pending. 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 Companies were namedoperating companies; dismissed FirstEnergy as respondents in a regulatory proceedingdefendant; ruled that the U.S.-Canada Power System Outage Task Force Report was initiated atnot admissible into evidence; and gave the plaintiffs additional time to amend their complaints to otherwise comply with the PUCO’s underlying order. Also, most complainants, along with the FirstEnergy companies, filed applications for rehearing with the PUCO over various rulings contained in responsethe March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to complaints alleging failureallow 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 that provide reasonabletheir service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed an amended complaint and adequate service stemming primarily from the August 14, 2003 power outages.named FirstEnergy companies have answered and also have filed a motion to dismiss each action. These motions are pending. Additionally, on June 23, 2006, one of the insurance carrier complainants filed an appeal with the Ohio Supreme Court over the PUCO’s denial of their motion for rehearing on the issue of the admissibility of the Task Force Report and the dismissal of FirstEnergy Corp. as a respondent. Briefing is expected to be completed on this appeal by mid-September. It is unknown when the Supreme Court will rule on the appeal. No estimate of potential liability is available for any of these cases.
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.
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 May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.
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. On July 8, 2005, FENOC requested an additional 120 days to respond to the NOV. TE has accrued the remaining liability for its share of the proposed fine of $1.6 million during the first quarter of 2005.
If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability based on events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or any of its subsidiaries' financial condition and results of operations.
Effective July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens.
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 preceding two years. FENOC operates the Perry Nuclear Power Plant, in which TE has a 19.91% interest (however, See Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which will include owned portions of the plant). 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. On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. 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.Other Legal Matters
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 now repealed 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 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 of a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. Both filings were consolidated for hearing and decision described above. 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. On May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s complaint and approving the related tariffs, thus affirming OE’s entitlement to recovery of its transition charges. The City of Huron filed an application for rehearing of the PUCO’s decision on June 9, 2006 and OE filed a memorandum in opposition to that application on June 19, 2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The City of Huron has 60 days from the denial of rehearing to appeal the PUCO’s decision. 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 13(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
| SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"
|
In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. TE will adopt this Statement effective January 1, 2006.
FIN 47, "Accounting48 - “Accounting for Conditional Asset Retirement ObligationsUncertainty in Income Taxes - an interpretation of FASB Statement No. 143"109.”
On March 30, 2005, In June 2006, the FASB issued FIN 4748 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to clarify the scopebe taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and timingtransition. The evaluation of liability recognition for conditional asset retirement obligations. Undera tax position in accordance with this interpretation companies are requiredwill be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit 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.financial statements. This Interpretationinterpretation is effective no later than the end offor fiscal years endingbeginning after December 15, 2005. Therefore, TE will adopt this Interpretation in the fourth quarter of 2005.2006. TE is currently evaluating the effectimpact of this Interpretation will have on its financial statements.Statement.
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 indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, TE continues to evaluate its investments as required by existing authoritative guidance.
PENNSYLVANIA POWER COMPANY | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In thousands) | | STATEMENTS OF INCOME | | | | | | | | | | | | | | | | | | | | | OPERATING REVENUES | | $ | 134,282 | | $ | 134,615 | | $ | 268,766 | | $ | 277,238 | | | | | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | Fuel | | | 5,526 | | | 5,855 | | | 11,146 | | | 12,061 | | | Purchased power | | | 42,726 | | | 44,095 | | | 89,706 | | | 92,603 | | | Nuclear operating costs | | | 19,765 | | | 17,180 | | | 39,713 | | | 35,803 | | | Other operating costs | | | 16,743 | | | 15,474 | | | 29,511 | | | 29,159 | | | Provision for depreciation | | | 3,810 | | | 3,472 | | | 7,504 | | | 6,834 | | | Amortization of regulatory assets | | | 9,833 | | | 10,027 | | | 19,715 | | | 20,103 | | | General taxes | | | 6,444 | | | 4,488 | | | 12,916 | | | 11,122 | | | Income taxes | | | 13,232 | | | 14,846 | | | 25,653 | | | 29,884 | | | Total operating expenses and taxes | | | 118,079 | | | 115,437 | | | 235,864 | | | 237,569 | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 16,203 | | | 19,178 | | | 32,902 | | | 39,669 | | | | | | | | | | | | | | | | | OTHER INCOME (net of income taxes) | | | 819 | | | 560 | | | 74 | | | 1,542 | | | | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | | | | Interest expense | | | 2,787 | | | 2,798 | | | 5,106 | | | 5,523 | | | Allowance for borrowed funds used during construction | | | (1,476 | ) | | (1,004 | ) | | (2,843 | ) | | (1,926 | ) | | Net interest charges | | | 1,311 | | | 1,794 | | | 2,263 | | | 3,597 | | | | | | | | | | | | | | | | | NET INCOME | | | 15,711 | | | 17,944 | | | 30,713 | | | 37,614 | | | | | | | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | 738 | | | 640 | | | 1,378 | | | 1,280 | | | | | | | | | | | | | | | | | EARNINGS ON COMMON STOCK | | $ | 14,973 | | $ | 17,304 | | $ | 29,335 | | $ | 36,334 | | | | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 15,711 | | $ | 17,944 | | $ | 30,713 | | $ | 37,614 | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME | | | - | | | - | | | - | | | - | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 15,711 | | $ | 17,944 | | $ | 30,713 | | $ | 37,614 | | | | | | | | | | | | | | | | | | 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 STATEMENTS OF INCOME | | (Unaudited) | | | | | | | | | | | | | | Three Months Ended | | Six Months Ended | | | | June 30, | | June 30, | | | | 2006 | | 2005 | | 2006 | | 2005 | | STATEMENTS OF INCOME | (In thousands) | | REVENUES | $ | 80,650 | | $ | 134,282 | | $ | 163,369 | | $ | 268,766 | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | Fuel | | - | | | 5,526 | | | - | | | 11,146 | | | Purchased power | | 56,513 | | | 42,726 | | | 111,269 | | | 89,706 | | | Nuclear operating costs | | - | | | 19,765 | | | - | | | 39,713 | | | Other operating costs | | 14,124 | | | 16,743 | | | 28,328 | | | 29,511 | | | Provision for depreciation | | 1,695 | | | 3,810 | | | 4,126 | | | 7,504 | | | Amortization of regulatory assets | | - | | | 9,833 | | | 3,411 | | | 19,715 | | | General taxes | | 5,670 | | | 6,444 | | | 11,504 | | | 12,916 | | | Total expenses | | 78,002 | | | 104,847 | | | 158,638 | | | 210,211 | | | | | | | | | | | | | | | | OPERATING INCOME | | 2,648 | | | 29,435 | | | 4,731 | | | 58,555 | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | Miscellaneous income | | 3,388 | | | 924 | | | 6,851 | | | (223 | ) | | Interest expense | | (1,407 | ) | | (2,787 | ) | | (5,362 | ) | | (5,106 | ) | | Capitalized interest | | 48 | | | 1,476 | | | 82 | | | 2,843 | | | Total other income (expense) | | 2,029 | | | (387 | ) | | 1,571 | | | (2,486 | ) | | | | | | | | | | | | | | | INCOME TAXES | | 1,928 | | | 13,337 | | | 2,807 | | | 25,356 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | 2,749 | | | 15,711 | | | 3,495 | | | 30,713 | | | | | | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | 155 | | | 738 | | | 311 | | | 1,378 | | | | | | | | | | | | | | | | EARNINGS ON COMMON STOCK | $ | 2,594 | | $ | 14,973 | | $ | 3,184 | | $ | 29,335 | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements. |
PENNSYLVANIA POWER COMPANY | PENNSYLVANIA POWER COMPANY | | PENNSYLVANIA POWER COMPANY | | | | | | | | | | | | | CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | (Unaudited) | | (Unaudited) | | | | | June 30, | | December 31, | | June 30, | | December 31, | | | | | 2005 | | 2004 | | 2006 | | 2005 | | | | | (In thousands) | | (In thousands) | | ASSETS | | | | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 38 | | $ | 24 | | | Receivables - | | | | | | | | | Customers (less accumulated provisions of $1,073,000 and $1,087,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 38,303 | | | 44,555 | | | Associated companies | | | 81,688 | | | 115,441 | | | Other | | | 1,332 | | | 2,889 | | | Notes receivable from associated companies | | | 1,838 | | | 1,699 | | | Prepayments and other | | | 17,728 | | | 86,995 | | | | | | 140,927 | | | 251,603 | | UTILITY PLANT: | | | | | | | | | | | | | In service | | $ | 892,826 | | $ | 866,303 | | | 365,959 | | | 359,069 | | | Less - Accumulated provision for depreciation | | | 371,569 | | | 356,020 | | | 131,181 | | | 129,118 | | | | | | 521,257 | | | 510,283 | | | 234,778 | | | 229,951 | | | Construction work in progress - | | | | | | | | | | Electric plant | | | 122,232 | | | 104,366 | | | | Nuclear fuel | | | - | | | 3,362 | | | | | | | 122,232 | | | 107,728 | | | | Construction work in progress- | | | 5,457 | | | 3,775 | | | | | | 643,489 | | | 618,011 | | | 240,235 | | | 233,726 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | | | | Nuclear plant decommissioning trusts | | | 144,704 | | | 143,062 | | | | Long-term notes receivable from associated companies | | | 32,795 | | | 32,985 | | | 276,052 | | | 283,248 | | | Other | | | 526 | | | 722 | | | 350 | | | 351 | | | | | | 178,025 | | | 176,769 | | | 276,402 | | | 283,599 | | CURRENT ASSETS: | | | | | | | | | | Cash and cash equivalents | | | 24 | | | 38 | | | | Notes receivable from associated companies | | | 448 | | | 431 | | | | Receivables - | | | | | | | | | | Customers (less accumulated provisions of $966,000 and $888,000, | | | | | | | | | | respectively, for uncollectible accounts) | | | 46,545 | | | 44,282 | | | | Associated companies | | | 10,632 | | | 23,016 | | | | | | | | | | | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Prepaid pension costs | | | 43,056 | | | 42,243 | | | Other | | | 939 | | | 1,656 | | | 1,775 | | | 3,829 | | | Materials and supplies, at average cost | | | 38,729 | | | 37,923 | | | | Prepayments and other | | | 17,184 | | | 8,924 | | | | | | | 114,501 | | | 116,270 | | | 44,831 | | | 46,072 | | | | | | | | | | | | | | | | | DEFERRED CHARGES | | | 9,915 | | | 10,106 | | | | | | $ | 945,930 | | $ | 921,156 | | $ | 702,395 | | $ | 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 | | | 65,035 | | | 64,690 | | | | Accumulated other comprehensive loss | | | (13,706 | ) | | (13,706 | ) | | | Retained earnings | | | 109,030 | | | 87,695 | | | | Total common stockholder's equity | | | 349,059 | | | 327,379 | | | | Preferred stock | | | 14,105 | | | 39,105 | | | | Long-term debt and other long-term obligations | | | 121,167 | | | 133,887 | | | | | | | 484,331 | | | 500,371 | | | LIABILITIES AND CAPITALIZATION | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | | | | | | | Currently payable long-term debt | | | 25,774 | | | 26,524 | | $ | 15,474 | | $ | 69,524 | | | Short-term borrowings - | | | | | | | | | | | | | | | Associated companies | | | 25,597 | | | 11,852 | | | 2,161 | | | 12,703 | | | Other | | | 20,000 | | | - | | | 19,000 | | | - | | | Accounts payable - | | | | | | | | | | | | | | | Associated companies | | | 25,282 | | | 46,368 | | | 20,420 | | | 73,444 | | | Other | | | 2,627 | | | 1,436 | | | 2,073 | | | 1,828 | | | Accrued taxes | | | 26,158 | | | 14,055 | | | 23,029 | | | 28,632 | | | Accrued interest | | | 1,988 | | | 1,872 | | | 1,070 | | | 1,877 | | | Other | | | 8,712 | | | 8,802 | | | 6,874 | | | 8,086 | | | | | | 136,138 | | | 110,909 | | | 90,101 | | | 196,094 | | 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 | | | 40,281 | | | 37,097 | | | Total common stockholder's equity | | | 300,117 | | | 296,933 | | | Preferred stock | | | 14,105 | | | 14,105 | | | Long-term debt and other long-term obligations | | | 123,343 | | | 130,677 | | | | | | 437,565 | | | 441,715 | | NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | Accumulated deferred income taxes | | | 84,400 | | | 93,418 | | | 63,698 | | | 66,576 | | | Asset retirement obligation | | | 142,872 | | | 138,284 | | | | Retirement benefits | | | 50,697 | | | 49,834 | | | 46,845 | | | 45,967 | | | Regulatory liabilities | | | 36,888 | | | 18,454 | | | 58,822 | | | 58,637 | | | Other | | | 10,604 | | | 9,886 | | | 5,364 | | | 6,011 | | | | | | 325,461 | | | 309,876 | | | 174,729 | | | 177,191 | | COMMITMENTS AND CONTINGENCIES (Note 13) | | | | | | | | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | $ | 945,930 | | $ | 921,156 | | $ | 702,395 | | $ | 815,000 | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of | | | | | | | | | | these balance sheets. | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets. | | 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 | PENNSYLVANIA POWER COMPANY | | PENNSYLVANIA POWER COMPANY | | | | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | CONSOLIDATED STATEMENTS OF CASH FLOWS | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | (Unaudited) | | (Unaudited) | | | | | | | | | | | | | | | | | | | | | | Three Months Ended | | Six Months Ended | | | Six Months Ended | | | | June 30, | | June 30, | | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | 2006 | | | 2005 | | | | | (In thousands) | | | (In thousands) | | | | | | | | | | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | | | | | | | | Net income | | $ | 15,711 | | $ | 17,944 | | $ | 30,713 | | $ | 37,614 | | | $ | 3,495 | | $ | 30,713 | | | Adjustments to reconcile net income to net cash from | | | | | | | | | | | | | | | | operating activities - | | | | | | | | | | | | | | | | Adjustments to reconcile net income to net cash from operating activities - | | | | | | | | | | Provision for depreciation | | | 3,810 | | | 3,472 | | | 7,504 | | | 6,834 | | | | 4,126 | | | 7,504 | | | Amortization of regulatory assets | | | 9,833 | | | 10,027 | | | 19,715 | | | 20,103 | | | | 3,411 | | | 19,715 | | | Nuclear fuel and other amortization | | | 4,138 | | | 4,431 | | | 8,278 | | | 8,996 | | | | - | | | 8,278 | | | Deferred income taxes and investment tax credits, net | | | (2,644 | ) | | (545 | ) | | (4,955 | ) | | (2,351 | ) | | | (2,383 | ) | | (4,955 | ) | | Decrease (increase) in operating assets - | | | | | | | | | | | | | | | | | | | | | | Receivables | | | (1,054 | ) | | 19,948 | | | 10,838 | | | 19,734 | | | | 41,562 | | | 10,838 | | | Materials and supplies | | | (1,024 | ) | | (1,221 | ) | | (806 | ) | | (2,296 | ) | | | - | | | (806 | ) | | Prepayments and other current assets | | | 5,221 | | | 5,192 | | | (8,260 | ) | | (8,141 | ) | | | 69,267 | | | (8,260 | ) | | Increase (decrease) in operating liabilities - | | | | | | | | | | | | | | | | | | | | | | Accounts payable | | | (17,005 | ) | | (22,368 | ) | | (19,895 | ) | | (18,628 | ) | | | (52,779 | ) | | (19,895 | ) | | Accrued taxes | | | 683 | | | (4,023 | ) | | 12,103 | | | 4,786 | | | | (5,602 | ) | | 12,103 | | | Accrued interest | | | 374 | | | 527 | | | 116 | | | (1,429 | ) | | | (807 | ) | | 116 | | | Other | | | (315 | ) | | 1,084 | | | 463 | | | 3,941 | | | | (3,290 | ) | | 463 | | | Net cash provided from operating activities | | | 17,728 | | | 34,468 | | | 55,814 | | | 69,163 | | | | 57,000 | | | 55,814 | | | | | | | | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | New Financing - | | | | | | | | | | | | | | | | | | | | | | Short-term borrowings, net | | | 34,953 | | | - | | | 33,745 | | | 22,203 | | | | 8,458 | | | 33,745 | | | Redemptions and Repayments - | | | | | | | | | | | | | | | | | | | | | | Preferred stock | | | (37,750 | ) | | - | | | (37,750 | ) | | - | | | | - | | | (37,750 | ) | | Long-term debt | | | (810 | ) | | (487 | ) | | (810 | ) | | (42,789 | ) | | | (61,899 | ) | | (810 | ) | | Short-term borrowings, net | | | - | | | (6,881 | ) | | - | | | - | | | | - | | | - | | | Dividend Payments - | | | | | | | | | | | | | | | | | | | | | | Common stock | | | - | | | (15,000 | ) | | (8,000 | ) | | (23,000 | ) | | | - | | | (8,000 | ) | | Preferred stock | | | (738 | ) | | (640 | ) | | (1,378 | ) | | (1,280 | ) | | | (311 | ) | | (1,378 | ) | | Net cash used for financing activities | | | (4,345 | ) | | (23,008 | ) | | (14,193 | ) | | (44,866 | ) | | | (53,752 | ) | | (14,193 | ) | | | | | | | | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | Property additions | | | (12,571 | ) | | (17,412 | ) | | (41,093 | ) | | (31,410 | ) | | | (10,216 | ) | | (41,093 | ) | | Contributions to nuclear decommissioning trusts | | | (398 | ) | | (398 | ) | | (797 | ) | | (797 | ) | | | Proceeds from nuclear decommissioning trust fund sales | | | | - | | | 36,995 | | | Investments in nuclear decommissioning trust funds | | | | - | | | (37,792 | ) | | Loan repayments from associated companies | | | 192 | | | 6,127 | | | 173 | | | 6,011 | | | | 7,057 | | | 173 | | | Other | | | (620 | ) | | 221 | | | 82 | | | 1,897 | | | | (75 | ) | | 82 | | | Net cash used for investing activities | | | (13,397 | ) | | (11,462 | ) | | (41,635 | ) | | (24,299 | ) | | | (3,234 | ) | | (41,635 | ) | | | | | | | | | | | | | | | | | | | | | | | | Net decrease in cash and cash equivalents | | | (14 | ) | | (2 | ) | | (14 | ) | | (2 | ) | | | Net increase (decrease) in cash and cash equivalents | | | | 14 | | | (14 | ) | | Cash and cash equivalents at beginning of period | | | 38 | | | 40 | | | 38 | | | 40 | | | | 24 | | | 38 | | | Cash and cash equivalents at end of period | | $ | 24 | | $ | 38 | | $ | 24 | | $ | 38 | | | $ | 38 | | $ | 24 | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of | | | | these statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements. | | 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 subsidiarysubsidiaries as of June 30, 2005,2006, and the related consolidated statementsstatement of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2006 and 2005 and 2004.the consolidated statement of cash flows for the six-month period ended June 30, 2006 and 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 have 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[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)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 July 29, 2005August 4, 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 In 2005, Penn and 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 comparative earnings 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 during 2006 (see Outlook -- Regulatory Matters).
The effects on Penn’s results of operations in the second quarter and first six months of 2006 compared to the same periods of 2005 from the generation asset transfers are summarized in the following table:
Intra-System Generation Asset Transfers | Income Statement Effects | | Three Months | | | Six Months | | Increase (Decrease) | | (In millions) | | | Revenues: | | | | | | | | Non-nuclear generating units rent | (a) | $ | (5 | ) | | $ | (10 | ) | | Nuclear generated KWH sales | (b) | | (38 | ) | | | (76 | ) | | Total - Revenues Effect | | | (43 | ) | | | (86 | ) | | Expenses: | | | | | | | | | | Fuel costs - nuclear | (c) | | (5 | ) | | | (11 | ) | | Nuclear operating costs | (c) | | (20 | ) | | | (40 | ) | | Provision for depreciation | (d) | | (1 | ) | | | (3 | ) | | General taxes | (e) | | (1 | ) | | | (1 | ) | | Total - Expenses Effect | | | (27 | ) | | | (54 | ) | | Operating Income Effect | | | (16 | ) | | | (32 | ) | | Other Income: | | | | | | | | | | Interest income from notes receivable | (f) | | 2 | | | | 5 | ) | | Capitalized Interest | (g) | | (1 | ) | | | (3 | ) | | Total - Other Income Effect | | | 1 | | | | 2 | | | Income taxes | (h) | | (6 | ) | | | (12 | ) | | Net Income Effect | | $ | (9 | ) | | $ | (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 allowance for borrowed funds used during construction on nuclear capital expenditures. | | (h) Income tax effect of the above adjustments. | | | | |
Results of Operations
Earnings on common stock in the second quarter of 20052006 decreased to $15$2.6 million from $17$15 million in the second quarter of 2004. The lower2005. During the first six months of 2006 earnings resulted primarily from increased operating expenses and taxes. Earnings on common stock decreased to $3.2 million from $29 million in the first six months of 20052005. The lower earnings resulted principally from the generation asset transfer effects shown in the table above.
Revenues
Revenues decreased to $29by $54 million, from $36or 40%, and $105 million, or 39%, in the second quarter of 2006 and the first six months of 2006, respectively, as compared with the same period of 2004.2005, primarily due to the generation asset transfer impact displayed in the table above. Excluding the effects of the asset transfer, revenues decreased by $11 million, or 12% and $19 million, or 11%, in the second quarter and the first six months of 2006, respectively. The lower earningsdecreases in the second quarter and the first half of 2006 resulted from decreased operatinglower distribution revenues ($9 million and other income,$18 million, respectively) primarily reflecting the completion of Penn's generation-related transition cost recovery under Penn’s rate restructuring plan, and lower wholesale revenues ($6 million and $12 million, respectively) resulting from the termination of a wholesale sales agreement with a non-affiliate in December 2005. These decreases were partially offset by lower operating expenses and taxes and lower net interest charges.
Operatingan increase in retail generation revenues decreased by $0.3of $5 million in the second quarter of 2005 compared2006 and $11 million in the first six months of 2006, primarily from higher composite unit prices associated with a 5% rate increase for generation permitted by the second quarter of 2004. The lower revenues primarily resulted from a $9 million decrease in wholesale sales to FES due to less nuclearPPUC for all customer classes - total retail generation available for sale. Higher retail electric generation revenues of $5 million resulted from increased KWH sales to residential and commercial customers, primarily due to cooler weather in the second quarter of 2005 in Penn's service area. These increases were partially offset by a $0.2 million decrease in revenues from industrial customers, reflecting lower KWH sales volume (11.7%) due in part to a 30.4% decrease in sales to a steel customer.remained substantially unchanged.
A $3 million increase in Lower distribution throughput revenues was primarily due to higher KWH deliveries to residential and commercial customers due to the changes in weather. This increase in revenue was partially offset by lower KWH sales and unit prices for industrial customers. The changes in unit prices are attributable to changes in Penn's CTC rate schedules in April 2005 as a result of the annual CTC reconciliation.
Operating revenues decreased by $8 million, or 3%, in the first six months of 2005 compared with the same period of 2004. The lower revenues primarily resulted from an $18 million decrease in wholesale sales to FES due to less nuclear generation available for sale. Retail generation electric revenues increased by $8 million in all customer sectors due to higher retail generation KWH sales and higher composite unit prices. Industrial revenues increased by $2 million due to higher unit prices ($4 million), partially offset by a $2 million decrease due to lower KWH sales, which reflect in part an 18.6% decrease in sales to a steel customer.
In the first six months of 2005, distribution throughput revenues increased by $0.2 million primarily due to higher KWH deliveries to residential and commercial customers, partially offset by lower unit prices for commercial and industrial customers. Colder weather contributed to the higher KWH deliveries, and the changes in unit prices are attributable to changes in Penn's CTC rate schedules in April 2005.
Changes in kilowatt-hour sales by customer class in the second quarter and first six months of 20052006 reflect the impact of milder weather conditions compared to the same periods of 2005. Higher KWH deliveries to industrial customers in both periods of 2006 are largely due to increased demand from the correspondingsteel sector.
Changes in distribution deliveries in the second quarter and the first six months of 2006 from the same periods of 20042005 are summarized in the following table:
| | | Three | | Six | | | Changes in KWH Sales | | Months | | Months | | | Changes in Distribution Deliveries | | | Three Months | | Six Months | | Increase (Decrease) | | | | | | | | | | | | Electric Generation: | | | | | | | | Retail | | | 4.5 | % | | 2.5 | % | | | Wholesale | | | (7.4 | )% | | (7.6 | )% | | Total Electric Generation Sales | | | (2.8 | )% | | (3.6 | )% | | | | | | | | | | | | Distribution Deliveries: | | | | | | | | | | | | | Residential | | | 22.6 | % | | 8.2 | % | | | (7.8) | % | | (4.9) | % | | Commercial | | | 11.7 | % | | 6.5 | % | | | (4.1) | % | | (2.7) | % | | Industrial | | | (11.7 | )% | | (5.7 | )% | | | 10.3 | % | | 7.2 | % | Total Distribution Deliveries | | | 4.5 | % | | 2.5 | % | | | - | % | | (0.04) | % | | | | | | | | | | | | | | | | | | | | | | | |
Operating Expenses and Taxes
Total operating expenses and taxes increaseddecreased by $3$27 million in the second quarter and decreased by $2$52 million in the first six months of 20052006 from the same periods last year. Theof 2005 principally due to the generation asset transfer impact as shown previously. Excluding the asset transfer effects, the following table presents changes from the prior year by expense category.category:
| | | Three | | Six | | Operating Expenses and Taxes - Changes | | Months | | Months | | | | | (In millions) | | Increase (Decrease) | | | | | | | Fuel costs | | $ | - | | $ | (1 | ) | | Purchased power costs | | | (1 | ) | | (3 | ) | | Nuclear operating costs | | | 3 | | | 4 | | | Other operating costs | | | 1 | | | - | | | General taxes | | | 2 | | | 2 | | | Income taxes | | | (2 | ) | | (4 | ) | Net increase (decrease) in operating expenses and taxes | | $ | 3 | | $ | (2 | ) | | | | | | | | | |
Expenses - Changes | | Three Months | | Six Months | | | | | (In millions) | | Increase (Decrease) | | | | | | | Purchased power costs | | $ | 14 | | $ | 21 | | | Other operating costs | | | (3 | ) | | (1 | ) | | Provision for depreciation | | | (1 | ) | | - | | | Amortization of regulatory assets | | | (10 | ) | | (16 | ) | | General Taxes | | | - | | | (1 | ) | Net change in expenses | | $ | - | | $ | 3 | | | | | | | | | | | | | | | | | | | |
Lower fuel costs in the first six months of 2005, compared with the same period of 2004, resulted from reduced nuclear generation. LowerIncreased purchased power costs in the second quarter and the first halfsix months of 2005 reflected lower unit prices for power. Nuclear operating costs increased in both2006, compared with the same periods of 2005, compared to the corresponding periods of 2004,resulted from higher unit prices associated with a new power supply agreement with FES, partially offset by decreases in KWH purchased due to lower generation sales requirements. Other operating costs decreased primarily due to lower employee benefit costs and a Perry scheduled refueling outage (including an unplanned extension)decrease in the first and second quartersuse of 2005, a Beaver Valley Unit 2 scheduled refueling outageoutside contractors for tree trimming. The provision for depreciation included an immaterial pretax adjustment of $0.7 million ($0.4 million net of tax) applicable to prior periods.
Amortization of regulatory assets was lower in the second quarter and the first six months of 2006 as compared to the same periods of 2005 due to the completion of Penn's rate restructuring plan and the absence of nuclear refueling outages in the first half of last year. related transition cost amortization.
Other operating costsIncome (Expense)
Investment income increased $2 million in the second quarter and $7 million the first six months of 2006, compared with the same periods of 2005, primarily due to increased vegetation management expenses and MISO Day 2 expenses that began in the second quarterimpact of 2005. General taxes increased in both periods of 2005 primarily because of higher property and gross receipts taxes.
Other Income
Other income (net of income taxes) increased slightly in the second quarter of 2005 and decreased by $1 million in the first six months of 2005, compared with the same periods in 2004. The decrease in the first half of 2005 was due to liabilities recognized in the first quarter of 2005 for a $0.7 million civil penalty and $0.8 million for probable future cash contributions toward environmentally beneficial projects related to the Sammis Plant settlement (see Outlook - Environmental Matters) and the absence of a $1 million gain from the sale of an investment in the first six months of 2004.generation asset transfer.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $0.5 millionwere substantially unchanged in the second quarter of 2005 and $1increased $3 million in the first six months as compared to the same periods of 2005 fromprimarily due to the corresponding periods last year, reflecting redemptionsreduction of $35 million in total principal amount of debt securities sincecapitalized interest related to the second quarter of 2004.generation asset transfer.
Capital Resources and Liquidity
Penn’s cash requirements in 2006 for operating expenses, construction expenditures and scheduled debt maturities and preferred stock redemptions are expected to be met 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
As of June 30, 2005, Penn had $24,000$38,000 of cash and cash equivalents as of June 30, 2006 compared with $38,000$24,000 as of December 31, 2004.2005. The major sources offor changes in these balances are summarized below.
Cash Flows From Operating Activities
Net cash provided from operating activities in the second quarter and first six months of 2005,2006, compared with the corresponding 2004 periods,2005 period, was as follows:
| | | Six Months Ended | | | | | June 30, | | Operating Cash Flows | | 2006 | | 2005 | | | | | | (in millions) | | Cash earnings (*) | | $ | 9 | | $ | 62 | | | Working capital and other | | | 48 | | | (6 | ) | | Net cash provided from operating activities | | $ | 57 | | $ | 56 | | | | | | | | | | | | | | | | | | | | (*) Cash earnings are a non-GAAP measure (see reconciliation below). |
| | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | Operating Cash Flows | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In millions) | | | | | | | | | | | | | Cash earnings (*) | | $ | 32 | | $ | 36 | | $ | 62 | | $ | 74 | | | Working capital and other | | | (14 | ) | | (2 | ) | | (6 | ) | | (5 | ) | | Total cash flows form operating activities | | $ | 18 | | $ | 34 | | $ | 56 | | $ | 69 | | | | | | | | | | | | | | | | | (*) 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 | | Six Months Ended | | | | | June 30, | | June 30, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In millions) | | | | | | | | | | | | | | Net income (GAAP) | | $ | 16 | | $ | 18 | | $ | 31 | | $ | 38 | | | Non-cash charges (credits): | | | | | | | | | | | | | | | Provision for depreciation | | | 4 | | | 3 | | | 8 | | | 7 | | | Amortization of regulatory assets | | | 10 | | | 10 | | | 20 | | | 20 | | | Nuclear fuel and other amortization | | | 4 | | | 4 | | | 8 | | | 9 | | | Deferred income taxes and investment tax credits, net | | | (3 | ) | | - | | | (5 | ) | | (2 | ) | | Other non-cash items | | | 1 | | | 1 | | | - | | | 2 | | | Cash earnings (Non-GAAP) | | $ | 32 | | $ | 36 | | $ | 62 | | $ | 74 | | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30, | | Reconciliation of Cash Earnings | | 2006 | | 2005 | | | | | (In millions) | | | Net income (GAAP) | | $ | 3 | | $ | 31 | | | Non-cash charges (credits): | | | | | | | | | Provision for depreciation | | | 4 | | | 8 | | | Amortization of regulatory assets | | | 3 | | | 20 | | | Nuclear fuel and other amortization | | | - | | | | | | Deferred income taxes and investment tax credits, net | | | (2 | ) | | (5 | ) | | Other non-cash Items | | | 1 | | | - | | | Cash earnings (Non-GAAP) | | $ | 9 | | $ | 62 | |
The $4$53 million and $12 million decreasesdecrease in cash earnings infor the second quarterfirst six months of 2006, as compared to the corresponding period of 2005, is described above under “Results of Operations”, and six-month period, respectively, are described under "Resultsresulted principally from the impact of Operations."the generation asset transfer. The $12$54 million change in working capital change in the second quarter was primarily due to increases in cash provided from the settlement of receivables of $31 million and a $21$78 million change in receivables,prepayments and other current assets, principally as a result of the asset transfer discussed above. These variances were partially offset by changesincreased cash outflows from the settlement of $5 million in accounts payable of $33 million and $5 million in accrued taxes. The $1 million working capital change in the six month period was primarily due to a $9an $18 million change in receivables, almost entirely offset by changes of $1 million in accounts payable and $7 million in accrued taxes.
Cash Flows From Financing Activities
Net cash used for financing activities totaled $4 million in the second quarter of 2005, compared with $23 million in the same period last year. The $19 million decrease resulted primarily from an increase in net short-term borrowings, higher optional redemptions of preferred stock and reduced common stock dividends to OE in the second quarter of 2005, compared with the second quarter of 2004.
On May 16, 2005, Penn redeemed 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. The total par value of the preferred stock redeemed was $37.8 million.
Net cash used for financing activities totaled $14$54 million in the first six months of 2005,2006, compared with $45$14 million in the same period last year.of 2005. The $31$40 million increase resulted from $62 million of long-term debt redemptions in 2006 principally related to the generation asset transfer discussed above and a $25 million decrease resulted primarily from increasedin short-term borrowings, and optional redemptionspartially offset by decreases of $38 million in preferred stock reduced debt redemptions and a decreasereductions of $8 million in common stock dividendsdividend payments to OE inas compared to the first six months of 2005, compared with the corresponding 2004 period.2005.
Penn had $472,000$2 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $46$21 million of short-term indebtedness as of June 30, 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$44 million (including the utility money pool). Penn had the capability to issue $498$66 million of additional FMB on the basis of property additions and retired bonds as of June 30, 2005.2006. Based upon applicable earnings coverage tests, Penn could issue up to $373$290 million of preferred stock (assuming no additional debt was issued) as of June 30, 2005.2006.
OnShort-term borrowings outstanding as of June 14, 2005,30, 2006, consisted of $19 million of borrowings from affiliates. 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 $25 million under a receivables financing arrangement at rates based on bank commercial paper rates. The financing arrangements require payment of an annual facility fee of 0.125% on the entire finance limit. Penn Funding’s receivables financing agreements expire June 28, 2007. As a separate legal entity with separate creditors, it would have to satisfy its separate obligations to creditors before any of its remaining assets could be made available to Penn.
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, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES, and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility.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 andor the commitment termination date, as the same may be extended.date. Penn's borrowing limit under the facility is $50 million.
Under the revolving credit facility, borrowers may request the issuance of LOC’s expiring up to one year from the date of issuance. The stated amount of outstanding LOC’s 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 June 30, 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 June 30, 2006, Penn's debt to total capitalization as defined under the revolving credit facility was 34%.
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. 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 second quarterfirst six months of 20052006 was 2.93%4.86%.
In addition, 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 $25 million under a receivables financing arrangement. 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 June 30, 2005, the facility was drawn for $20 million. On July 15, 2005, the facility was renewed until June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.
Penn’sPenn's access to the 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 positive.
On May 16, 2005, S&P affirmed its 'BBB-' corporate credit ratings on FirstEnergy and its units and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmation and outlook revision reflects the successful restart of the three nuclear units from their respective outages that occurred during In the first halfsix months of 2005. S&P noted2006, pollution control notes that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projectedwere formerly obligations of Penn were refinanced and its nuclear operations further stabilize.
On July 18, 2005, Moody’s revised its rating outlook on FirstEnergybecame obligations of FGCO and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemmingNGC. The proceeds from the applicationrefinancings were used to repay a portion of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continuestheir associated company notes payable to achieve planned improvementsPenn. With those repayments, Penn redeemed pollution control notes in its operationsthe principal amount of $16.8 million at 5.9%, $12.7 million at 6.15%, $14.25 million at 6%, $10.3 million at 3.61%, and balance sheet.$6.95 million at 5.45%.
Cash Flows From Investing Activities
Net cash used infor investing activities totaled $13 million in the second quarter of 2005, compared with $11 million in the second quarter of 2004. The $2 million increase reflects a decrease in loan repayments from associated companies, partially offset by a decrease in property additions. Net cash used in investing activities totaled $42$3 million in the first six months of 2005,2006, compared with $24$42 million in the same period last year.of 2005. The $18$39 million increase was primarilydecrease in the 2006 period reflects a $31 million reduction in property additions, principally as a result of increased property additionsthe generation asset transfer discussed above and reduceda $7 million increase in loan repayments from associated companies.
During the secondlast half of 2005,2006, capital requirements for property additions are expected to be about $54 million, including $10 million for nuclear fuel.approximately $8 million. Penn expects to contribute up to $65 million (unfunded liability recognized as of June 30, 2005) for nuclear decommissioning in connection with the generation asset transfers described below, and has additional requirements of $0.5 million to meet sinking fund requirements of approximately $0.5 million for 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 $227approximately $90 million (excluding nuclear fuel), of which approximately $81$18 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $66 million, of which about $15 million relates to 2005. During the same periods, Penn’s nuclear fuel investments are expected to be reduced by approximately $53 million and $17 million, respectively, as the nuclear fuel is consumed. After completion of the asset transfers described further below, Penn’s future capital requirements are expected to be substantially reduced and the nuclear fuel obligations would be terminated.2006. Penn had no other material obligations as of June 30, 20052006 that have not been recognized on its Consolidated Balance Sheet.
On July 22, 2005, the Philadelphia Stock Exchange filed an application with the SEC for termination of the listing of the following three series of Penn’s cumulative preferred stock, $100 par value, as such series no longer met the Exchange’s technical listing requirements regarding the number of outstanding shares and the number of holders: 4.24% Series, 4.25% Series and 4.64% Series. The Exchange requested an effective date of August 12, 2005.
Equity Price RiskOUTLOOK
Included in The electric industry continues to transition to a more competitive environment and all of Penn’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $57 million as of both dates, June 30, 2005customers can select alternative energy suppliers. Penn continues to deliver power to residential homes and December 31, 2004. A hypothetical 10% decrease in prices quoted by stock exchanges would result inbusinesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. Penn has a $6 million reduction in fair value as of June 30, 2005.continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits.
FirstEnergy Intra-System Generation Asset TransfersRegulatory Matters
On May 13, 2005, Penn entered into an agreement to transfer its ownership interests in its nuclear and fossil generating facilities to NGC and FGCO, respectively. These transactions are being undertaken in connection with Penn’s restructuring plan that was approved by the PPUC under applicable Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plan, Penn’s generation assets were required to be separated from the regulated delivery business through transfers to a separate corporate entity. FENOC, a subsidiary of FirstEnergy, currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a master facility lease, leases the non-nuclear generation assets to be transferred and operates and maintains those assets. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.
Penn intends to transfer its interests in the nuclear generation assets to NGC through a spin-off by way of a dividend. FGCO intends to exercise a purchase option under the Master Lease to acquire Penn’s fossil generation assets. Consummation of the transactions is subject to receipt of all necessary regulatory authorizations and other consents and approvals. Penn expects to complete the asset transfers in the second half of 2005.
Regulatory Matters
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 $37 million and $18$59 million as of June 30, 20052006 and December 31, 2004, respectively,2005, and are included inunder Noncurrent Liabilities on the Consolidated Balance Sheets.
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 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. To the extent that an affiliate of Penn supplies a portion of the PLR load included in the RFP, authorization to make the affiliate sale must be obtained from the FERC. Hearings before the PPUC 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. On April 20, 2006, the PPUC approved the Recommended Decision with additional modifications to use an RFP process to obtain Penn's power supply requirements after 2006 through two separate solicitations. An initial solicitation was held for Penn in May 2006 with all tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results for the first solicitation. On July 18, 2006, the second PLR solicitation was held for Penn. The tranches for the Residential Group and Small Commercial Group were fully subscribed. However, supply was only acquired for three of the five tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved the submissions for the second bid. A residual solicitation is scheduled to be held on August 15, 2006 for the two remaining Large Commercial Group tranches. Acceptance of the winning bids is subject to approval by the PPUC.
On November 1, 2005, FES filed a power sales agreement for approval with the FERC that would permit Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. As discussed above, subsequent to the PPUC’s approval of Penn's plan for the RFP process to obtain its post 2006 power supply requirements, the customer power supply requirements for all of the residential and the small commercial sectors and the majority of the large commercial sector tranches have been fully subscribed and the bids approved by the PPUC. An additional solicitation for the remaining two large commercial sector tranches is scheduled for August 15, 2006. On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of April 28, 2006 and May 4, 2006, which together decided the issues associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the Commonwealth Court to review the PPUC’s decision to deny its recovery of certain PLR costs via a reconciliation mechanism and its decision to impose a geographic limitation on the sources of alternative energy credits. On June 7, 2006, the PaDEP filed a Petition for Review appealing the PPUC’s ruling on the method by which alternative energy credits may be acquired and traded. Penn is unable to predict the outcome of this appeal.
See Note 1411 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 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.
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.
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). Penn'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 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, including 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 in the form of a Consent Decree that was approved by the Court on July 11, 2005, and 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 capital expenditures currently estimatedand provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Those requirements will be $1.1 billion (primarily in the 2008 to 2011 time period).responsibility of FGCO. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchasepurchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million, of which Penn's share is $0.7 million. Results for the first quarter of 2005 included the penalties paid by OE and Penn of $7.8 million and $0.7 million, penalty payable byrespectively. OE and Penn also recognized liabilities in the first quarter of 2005 of $9.2 million and an $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.
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'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 websiteWeb site (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. FirstEnergy is also is proceeding with the implementation of the 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 new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, thatequipment. The 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 FirstEnergy’s 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. 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.
129 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 preceding two years. FENOC operates the Perry Nuclear Power Plant, in which Penn has a 5.24% interest (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which will include owned portions of the plant). 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. On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. 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 13(C)10(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.
New Accounting Standards and Interpretations
SFAS 154FIN 48 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"
In May 2005, the FASB issued SFAS 154 to change the requirements“Accounting for accounting and reporting a changeUncertainty in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Penn will adopt this Statement effective January 1, 2006.
FIN 47, "Accounting for Conditional Asset Retirement ObligationsIncome Taxes - an interpretation of FASB Statement No. 143"109.”
On March 30, 2005,In June 2006, the FASB issued FIN 4748 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to clarify the scopebe taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and timingtransition. The evaluation of liability recognition for conditional asset retirement obligations. Undera tax position in accordance with this interpretation companies are requiredwill be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit 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.financial statements. This Interpretationinterpretation is effective no later than the end offor fiscal years endingbeginning after December 15, 2005. Therefore, Penn will adopt this Interpretation in the fourth quarter of 2005.2006. Penn is currently evaluating the effectimpact of this Interpretation will have on its financial statements.Statement.
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 indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, Penn continues to evaluate its investments as required by existing authoritative guidance.
JERSEY CENTRAL POWER & LIGHT COMPANY | JERSEY CENTRAL POWER & LIGHT COMPANY | | JERSEY CENTRAL POWER & LIGHT 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 | | Six Months Ended | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | 2006 | | 2005 | | | | | (In thousands) | | | | | Restated | | | | Restated | | | | | | | STATEMENTS OF INCOME | | | | | | | | | | | (In thousands) | | | | | | | | | | | | | | | | | | | | | OPERATING REVENUES | | $ | 595,291 | | $ | 549,665 | | $ | 1,124,383 | | $ | 1,047,789 | | | REVENUES | | | $ | 611,484 | | $ | 595,291 | | $ | 1,187,276 | | $ | 1,124,383 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | EXPENSES | | | | | | | | | | | | | | | | Purchased power | | | 321,393 | | | 285,742 | | | 598,525 | | | 556,475 | | | | 343,045 | | | 321,393 | | | 658,755 | | | 598,525 | | | Other operating costs | | | 80,239 | | | 80,844 | | | 181,306 | | | 167,660 | | | | 72,105 | | | 80,239 | | | 155,133 | | | 181,306 | | | Provision for depreciation | | | 19,856 | | | 19,093 | | | 40,062 | | | 38,168 | | | | 20,826 | | | 19,856 | | | 41,454 | | | 40,062 | | | Amortization of regulatory assets | | | 70,250 | | | 67,949 | | | 138,624 | | | 132,434 | | | | 65,526 | | | 70,250 | | | 132,271 | | | 138,624 | | | Deferral of new regulatory assets | | | (27,765 | ) | | - | | | (27,765 | ) | | - | | | | - | | | (27,765 | ) | | - | | | (27,765 | ) | | General taxes | | | 14,824 | | | 14,738 | | | 30,264 | | | 30,670 | | | | 14,272 | | | 14,824 | | | 30,504 | | | 30,264 | | | Income taxes | | | 42,366 | | | 26,343 | | | 54,849 | | | 35,456 | | | | Total operating expenses and taxes | | | 521,163 | | | 494,709 | | | 1,015,865 | | | 960,863 | | | | Total expenses | | | | 515,774 | | | 478,797 | | | 1,018,117 | | | 961,016 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 74,128 | | | 54,956 | | | 108,518 | | | 86,926 | | | | 95,710 | | | 116,494 | | | 169,159 | | | 163,367 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | OTHER INCOME (net of income taxes) | | | 273 | | | 1,104 | | | 317 | | | 2,607 | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | Miscellaneous income | | | | 2,528 | | | 201 | | | 6,071 | | | 487 | | | Interest Expense | | | | (20,367 | ) | | (20,100 | ) | | (40,983 | ) | | (41,003 | ) | | Capitalized interest | | | | 1,037 | | | 437 | | | 1,929 | | | 840 | | | Total other income (expense) | | | | (16,802 | ) | | (19,462 | ) | | (32,983 | ) | | (39,676 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | | | | | Interest on long-term debt | | | 19,276 | | | 19,803 | | | 38,681 | | | 40,531 | | | | Allowance for borrowed funds used during construction | | | (437 | ) | | (151 | ) | | (840 | ) | | (271 | ) | | | Deferred interest | | | (916 | ) | | (891 | ) | | (1,827 | ) | | (1,814 | ) | | | Other interest expense | | | 1,155 | | | 463 | | | 2,979 | | | 853 | | | | Net interest charges | | | 19,078 | | | 19,224 | | | 38,993 | | | 39,299 | | | INCOME TAXES | | | | 38,632 | | | 42,729 | | | 62,190 | | | 55,939 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | | 55,323 | | | 36,836 | | | 69,842 | | | 50,234 | | | | 40,276 | | | 54,303 | | | 73,986 | | | 67,752 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | PREFERRED STOCK DIVIDEND REQUIREMENTS | | | 125 | | | 125 | | | 250 | | | 250 | | | | 125 | | | 125 | | | 250 | | | 250 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | EARNINGS ON COMMON STOCK | | $ | 55,198 | | $ | 36,711 | | $ | 69,592 | | $ | 49,984 | | | $ | 40,151 | | $ | 54,178 | | $ | 73,736 | | $ | 67,502 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 55,323 | | $ | 36,836 | | $ | 69,842 | | $ | 50,234 | | | $ | 40,276 | | $ | 54,303 | | $ | 73,986 | | $ | 67,752 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME: | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unrealized gain on derivative hedges | | | 36 | | | 59 | | | 105 | | | 44 | | | | 38 | | | 36 | | | 107 | | | 105 | | | Unrealized loss on available for sale securities | | | - | | | - | | | - | | | (8 | ) | | | Other comprehensive income | | | 36 | | | 59 | | | 105 | | | 36 | | | | Income tax related to other comprehensive income | | | (15 | ) | | - | | | (43 | ) | | 4 | | | | Income tax expense related to other comprehensive income | | | | 15 | | | 15 | | | 43 | | | 43 | | | Other comprehensive income, net of tax | | | 21 | | | 59 | | | 62 | | | 40 | | | | 23 | | | 21 | | | 64 | | | 62 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 55,344 | | $ | 36,895 | | $ | 69,904 | | $ | 50,274 | | | $ | 40,299 | | $ | 54,324 | | $ | 74,050 | | $ | 67,814 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an | | | | integral part of these statements. | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements. | | 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 | JERSEY CENTRAL POWER & LIGHT COMPANY | | JERSEY CENTRAL POWER & LIGHT COMPANY | | | | | | | | | | | CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | (Unaudited) | | (Unaudited) | | | | | June 30, | | December 31, | | | June 30, | | December 31, | | | | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In thousands) | | | (In thousands) | | ASSETS | | | | | | | | | | | CURRENT ASSETS: | | | | | | | | Cash and cash equivalents | | | $ | 95 | | $ | 102 | | | Receivables- | | | | | | | | | | Customers (less accumulated provisions of $3,078,000 and $3,830,000, | | | | | | | | | | respectively, for uncollectible accounts) | | | | 282,352 | | | 258,077 | | | Associated companies | | | | 142 | | | 203 | | | Other (less accumulated provisions of $206,000 and $204,000, | | | | | | | | | | respectively, for uncollectible accounts) | | | | 41,317 | | | 41,456 | | | Notes receivable - associated companies | | | | 27,766 | | | 18,419 | | | Materials and supplies, at average cost | | | | 2,012 | | | 2,104 | | | Prepayments (sales & use, corp. business, TEFA) taxes | | | | 110,787 | | | 10,137 | | | Prepayments and other | | | | 5,210 | | | 6,928 | | | | | | | 469,681 | | | 337,426 | | UTILITY PLANT: | | | | | | | | | | | | | | In service | | $ | 3,803,593 | | $ | 3,730,767 | | | | 3,983,859 | | | 3,902,684 | | | Less - Accumulated provision for depreciation | | | 1,409,221 | | | 1,380,775 | | | | 1,454,291 | | | 1,445,718 | | | | | | 2,394,372 | | | 2,349,992 | | | | 2,529,568 | | | 2,456,966 | | | Construction work in progress | | | 76,134 | | | 75,012 | | | | 77,325 | | | 98,720 | | | | | | 2,470,506 | | | 2,425,004 | | | | 2,606,893 | | | 2,555,686 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | | | | | Nuclear fuel disposal trust | | | | 165,132 | | | 164,203 | | | Nuclear plant decommissioning trusts | | | 139,831 | | | 138,205 | | | | 149,000 | | | 145,975 | | | Nuclear fuel disposal trust | | | 163,074 | | | 159,696 | | | | Long-term notes receivable from associated companies | | | 19,767 | | | 20,436 | | | | Other | | | 16,459 | | | 19,379 | | | | 2,069 | | | 2,580 | | | | | | 339,131 | | | 337,716 | | | | 316,201 | | | 312,758 | | CURRENT ASSETS: | | | | | | | | | | Cash and cash equivalents | | | 412 | | | 162 | | | | Receivables - | | | | | | | | | | Customers (less accumulated provisions of $3,101,000 and $3,881,000, | | | | | | | | | | respectively, for uncollectible accounts) | | | 273,361 | | | 201,415 | | | | Associated companies | | | 4,387 | | | 86,531 | | | | Other (less accumulated provisions of $241,000 and $162,000, | | | | | | | | | | respectively, for uncollectible accounts) | | | 35,824 | | | 39,898 | | | | Materials and supplies, at average cost | | | 2,258 | | | 2,435 | | | | Prepayments and other | | | 98,014 | | | 31,489 | | | | | | | 414,256 | | | 361,930 | | | DEFERRED CHARGES: | | | | | | | | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | Regulatory assets | | | 2,137,692 | | | 2,176,520 | | | | 2,121,811 | | | 2,226,591 | | | Goodwill | | | 1,983,699 | | | 1,985,036 | | | | 1,978,141 | | | 1,985,858 | | | Prepaid pension costs | | | | 150,760 | | | 148,054 | | | Other | | | 3,958 | | | 4,978 | | | | 16,410 | | | 17,733 | | | | | | 4,125,349 | | | 4,166,534 | | | | 4,267,122 | | | 4,378,236 | | | | | $ | 7,349,242 | | $ | 7,291,184 | | | $ | 7,659,897 | | $ | 7,584,106 | | CAPITALIZATION AND LIABILITIES | | | | | | | | | LIABILITIES AND CAPITALIZATION | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | | Currently payable long-term debt | | | $ | 57,586 | | $ | 207,231 | | | Notes payable- | | | | | | | | | | Associated companies | | | | 365,164 | | | 181,346 | | | Accounts payable- | | | | | | | | | | Associated companies | | | | 16,425 | | | 37,955 | | | Other | | | | 194,619 | | | 149,501 | | | Accrued taxes | | | | 45,295 | | | 54,356 | | | Accrued interest | | | | 20,278 | | | 19,916 | | | Cash collateral from suppliers | | | | 32,434 | | | 141,225 | | | Other | | | | 78,214 | | | 86,884 | | | | | | | 810,015 | | | 878,414 | | CAPITALIZATION: | | | | | | | | | | | | | | | | Common stockholder's equity - | | | | | | | | | | Common stock, $10 par value, authorized 16,000,000 shares - | | | | | | | | | | Common stockholder's equity- | | | | | | | | �� | | Common stock, $10 par value, authorized 16,000,000 shares- | | | | | | | | | | 15,371,270 shares outstanding | | $ | 153,713 | | $ | 153,713 | | | | 153,713 | | | 153,713 | | | Other paid-in capital | | | 3,014,583 | | | 3,013,912 | | | | 2,995,542 | | | 3,003,190 | | | Accumulated other comprehensive loss | | | (55,472 | ) | | (55,534 | ) | | | (1,966 | ) | | (2,030 | ) | | Retained earnings | | | 72,863 | | | 43,271 | | | | 104,626 | | | 55,890 | | | Total common stockholder's equity | | | 3,185,687 | | | 3,155,362 | | | | 3,251,915 | | | 3,210,763 | | | Preferred stock | | | 12,649 | | | 12,649 | | | | 12,649 | | | 12,649 | | | Long-term debt and other long-term obligations | | | 1,022,320 | | | 1,238,984 | | | | 1,162,407 | | | 972,061 | | | | | | 4,220,656 | | | 4,406,995 | | | CURRENT LIABILITIES: | | | | | | | | | | Currently payable long-term debt | | | 166,868 | | | 16,866 | | | | Notes payable - | | | | | | | | | | Associated companies | | | 279,105 | | | 248,532 | | | | Accounts payable - | | | | | | | | | | Associated companies | | | 13,900 | | | 20,605 | | | | Other | | | 163,524 | | | 124,733 | | | | Accrued taxes | | | 59,844 | | | 2,626 | | | | Accrued interest | | | 9,770 | | | 10,359 | | | | Other | | | 57,661 | | | 65,130 | | | | | | | 750,672 | | | 488,851 | | | | 4,426,971 | | | 4,195,473 | | NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | Power purchase contract loss liability | | | 1,202,184 | | | 1,268,478 | | | | 1,122,933 | | | 1,237,249 | | | Accumulated deferred income taxes | | | 691,505 | | | 645,741 | | | | 827,760 | | | 812,034 | | | Nuclear fuel disposal costs | | | 172,207 | | | 169,884 | | | | 179,039 | | | 175,156 | | | Asset retirement obligation | | | 74,869 | | | 72,655 | | | | 81,949 | | | 79,527 | | | Retirement benefits | | | 99,755 | | | 103,036 | | | | 72,520 | | | 72,454 | | | Other | | | 137,394 | | | 135,544 | | | | 138,710 | | | 133,799 | | | | | | 2,377,914 | | | 2,395,338 | | | | 2,422,911 | | | 2,510,219 | | COMMITMENTS AND CONTINGENCIES (Note 13) | | | | | | | | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | | $ | 7,349,242 | | $ | 7,291,184 | | | $ | 7,659,897 | | $ | 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. | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these balance sheets. | | 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) | | | | | | | | Six Months Ended | | | | | June 30, | | | | | 2006 | | 2005 | | | | | | | Restated | | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 73,986 | | $ | 67,752 | | | Adjustments to reconcile net income to net cash from operating activities - | | | | | | | | | Provision for depreciation | | | 41,454 | | | 40,062 | | | Amortization of regulatory assets | | | 132,271 | | | 138,624 | | | Deferral of new regulatory assets | | | - | | | (27,765 | ) | | Deferred purchased power and other costs | | | (134,759 | ) | | (126,265 | ) | | Deferred income taxes and investment tax credits, net | | | 10,942 | | | 16,426 | | | Accrued compensation and retirement benefits | | | (3,436 | ) | | (8,029 | ) | | Cash collateral from (returned to) suppliers | | | (108,791 | ) | | 198 | | | Decrease (increase) in operating assets - | | | | | | | | | Receivables | | | (24,074 | ) | | 14,271 | | | Materials and supplies | | | 91 | | | 177 | | | Prepayments and other current assets | | | (98,932 | ) | | (66,525 | ) | | Increase (decrease) in operating liabilities - | | | | | | | | | Accounts payable | | | 23,589 | | | 32,087 | | | Accrued taxes | | | (9,062 | ) | | 58,139 | | | Accrued interest | | | 362 | | | 580 | | | Other | | | (1,642 | ) | | 16,856 | | | Net cash provided from (used for) operating activities | | | (98,001 | ) | | 156,588 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | 200,003 | | | - | | | Short-term borrowings, net | | | 183,818 | | | 30,572 | | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (157,659 | ) | | (63,327 | ) | | Dividend Payments- | | | | | | | | | Common stock | | | (25,000 | ) | | (40,000 | ) | | Preferred stock | | | (250 | ) | | (250 | ) | | Net cash provided from (used for) financing activities | | | 200,912 | | | (73,005 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (91,101 | ) | | (82,661 | ) | | Loan repayments from (loans to) associated companies, net | | | (9,347 | ) | | 670 | | | Proceeds from nuclear decommissioning trust fund sales | | | 109,505 | | | 53,782 | | | Investments in nuclear decommissioning trust funds | | | (110,952 | ) | | (55,229 | ) | | Other | | | (1,023 | ) | | 105 | | | Net cash used for investing activities | | | (102,918 | ) | | (83,333 | ) | | | | | | | | | | | Net increase (decrease) in cash and cash equivalents | | | (7 | ) | | 250 | | | Cash and cash equivalents at beginning of period | | | 102 | | | 162 | | | Cash and cash equivalents at end of period | | $ | 95 | | $ | 412 | | | | | | | | | | | 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 | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In thousands) | | | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | Net income | | $ | 55,323 | | $ | 36,836 | | $ | 69,842 | | $ | 50,234 | | | Adjustments to reconcile net income to net cash from | | | | | | | | | | | | | | | operating activities - | | | | | | | | | | | | | | | Provision for depreciation | | | 19,856 | | | 19,093 | | | 40,062 | | | 38,168 | | | Amortization of regulatory assets | | | 70,250 | | | 67,949 | | | 138,624 | | | 132,434 | | | Deferral of new regulatory assets | | | (27,765 | ) | | - | | | (27,765 | ) | | | | | Deferred purchased power and other costs | | | (52,906 | ) | | (40,408 | ) | | (126,265 | ) | | (78,390 | ) | | Deferred income taxes and investment tax credits, net | | | 9,258 | | | (19,977 | ) | | 16,426 | | | (19,747 | ) | | Accrued retirement benefit obligation | | | 1,447 | | | 2,946 | | | (3,281 | ) | | (8,768 | ) | | Accrued compensation, net | | | (10,161 | ) | | 39 | | | (4,748 | ) | | (816 | ) | | NUG power contract restructuring | | | - | | | 52,800 | | | - | | | 52,800 | | | Decrease (increase) in operating assets - | | | | | | | | | | | | | | | Receivables | | | (577 | ) | | 6,405 | | | 14,271 | | | 7,843 | | | Materials and supplies | | | 95 | | | (11 | ) | | 177 | | | 347 | | | Prepayments and other current assets | | | (75,775 | ) | | (64,080 | ) | | (66,525 | ) | | (39,704 | ) | | Increase (decrease) in operating liabilities - | | | | | | | | | | | | | | | Accounts payable | | | 62,477 | | | 16,294 | | | 32,087 | | | 945 | | | Accrued taxes | | | 18,341 | | | 14,288 | | | 57,218 | | | 63,768 | | | Accrued interest | | | (15,308 | ) | | (16,006 | ) | | (589 | ) | | (5,228 | ) | | Other | | | 4,731 | | | (23,388 | ) | | 17,054 | | | (19,064 | ) | | Net cash provided from operating activities | | | 59,286 | | | 52,780 | | | 156,588 | | | 174,822 | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | New Financing- | | | | | | | | | | | | | | | Long-term debt | | | - | | | 300,000 | | | - | | | 300,000 | | | Short-term borrowings, net | | | 74,310 | | | 7,552 | | | 30,572 | | | - | | | Redemptions and Repayments- | | | | | | | | | | | | | | | Long-term debt | | | (59,444 | ) | | (293,477 | ) | | (63,327 | ) | | (297,068 | ) | | Short-term borrowings, net | | | - | | | - | | | - | | | (72,192 | ) | | Dividend Payments- | | | | | | | | | | | | | | | Common stock | | | (20,000 | ) | | (15,000 | ) | | (40,000 | ) | | (20,000 | ) | | Preferred stock | | | (125 | ) | | (125 | ) | | (250 | ) | | (250 | ) | | Net cash used for financing activities | | | (5,259 | ) | | (1,050 | ) | | (73,005 | ) | | (89,510 | ) | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | Property additions | | | (54,537 | ) | | (55,213 | ) | | (82,661 | ) | | (83,425 | ) | | Loan repayments from (loans to) associated companies, net | | | 1,568 | | | 645 | | | 670 | | | (411 | ) | | Other | | | (687 | ) | | 2,838 | | | (1,342 | ) | | (1,465 | ) | | Net cash used for investing activities | | | (53,656 | ) | | (51,730 | ) | | (83,333 | ) | | (85,301 | ) | | | | | | | | | | | | | | | | | Net increase in cash and cash equivalents | | | 371 | | | - | | | 250 | | | 11 | | | Cash and cash equivalents at beginning of period | | | 41 | | | 282 | | | 162 | | | 271 | | | Cash and cash equivalents at end of period | | $ | 412 | | $ | 282 | | $ | 412 | | $ | 282 | | | | | | | | | | | | | | | | | | 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 June 30, 2005,2006, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2006 and 2005 and 2004.the consolidated statement of cash flows for the six-month period ended June 30, 2006 and 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 have 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[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 92(I) 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 tostatements] dated February 27, 2006, we expressed an unqualified opinion on those consolidated financial statements) dated March 7, 2005, 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.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 July 29, 2005August 4, 2006
JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONSAND 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 rates into unbundled service chargesconsolidated financial statements for the three months and transition cost recovery charges.six months ended June 30, 2005. The revisions are the result of a tax audit from the State of New Jersey, in 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 second quarter of 2005 increased2006 decreased to $55$40.2 million from $37$54.2 million in 2004. For the first six months of 2005, earnings on common stock increased to $70 million compared to $50 million for the same period of 2004.2005. The increase in earnings for both periodsdecrease was primarilyprincipally due to higher operating revenues andthe absence of the deferral of a new regulatory asset in 2005 and increased purchased power costs, partially offset by increases in purchased powerincreased revenues and decreased other operating costs. Other operating costs were also higher inIn the first six months of 20052006, earnings on common stock increased to $73.7 million compared to $67.5 million for the same period in 2004.2005. The increase was primarily due to higher revenues and lower other operating costs partially offset by increased purchased power costs and the absence of the regulatory asset deferred in 2005.
Operating revenuesRevenues
Revenues increased $46$16.2 million or 8.3%2.7% in the second quarter of 2006 and $77$62.9 million or 7.3% in5.6% for the first six months of 20052006 compared with the same periods in 2004.of 2005. The higher revenues in both periods were primarily due to increased retail electric generation revenuesrevenue increases ($3328.5 million forand $66.3 million in the second quarter and $51 million for the first six months of 2005) and distribution revenues2006, respectively), partially offset by wholesale revenue decreases ($227.6 million forin the second quarter and $34$5.8 million forin the first six months of 2005), partially offset by a decline2006). Distribution revenues declined $1.1 million in wholesale revenues ($4 million for the second quarter and $8of 2006 but increased $4.2 million forin the first six months of 2005).2006 compared to the same periods of the prior year.
HigherThe retail generation revenuesrevenue increases in both the second quarter and the first six months of 20052006 as compared to the previous year were due to higher unit prices resulting from the BGS auctions effective in May 2006 and May 2005, which partially offset declines in retail generation KWH sales. Revenue from residential customers increased $12.7 million and $27.6 million in the second quarter and the first six months of 2006, respectively, as compared to the same periods in 2005. Generation revenue from commercial customers also increased for the same periods by $15.3 million and $36.3 million, respectively. The milder weather in the second quarter and the first six months of 2006 as compared to the previous year (cooling degree days were 3.5% below the previous year and heating degree days were 18.6% below the previous year) resulted from increasedin lower KWH sales to residential customers in the second quarter and the first six months of 2006. The milder weather also resulted in overall lower KWH sales to commercial customers. Revenue from residential customers increased in the second quarter and first six months of 2005 by $222006 - more than offsetting the impact of commercial customers returning to JCP&L from alternative suppliers. Revenues from industrial customers increased $0.3 million and $36$2.1 million respectively. Commercial generation revenue increased for the same periods by $12 million and $20 million, respectively. The increases were attributable to higher KWH sales (residential - 18.2% and commercial - 10.0% in the second quarter and first six months of 2005; residential - 15.5%2006, respectively, as compared to the previous year, as a result of higher unit prices offsetting KWH sales decreases in the second quarter and commercial - 9.6%the first six months of 2006. Wholesale sales revenues decreased $7.6 million in the second quarter and $5.8 million for the first six months of 2005) primarily due2006 as compared to 2005 as lower customer shopping. Generation provided by alternative suppliers to residential and commercial customers as a percentunit prices offset KWH sales increases.
The decrease in distribution revenues of total sales delivered in JCP&L’s service area decreased by 11.1% and 5.4%, respectively,$1.1 million in the second quarter of 2006 compared to the same period of 2005 consists of two components, a $1.8 million increase in wires revenue and 11.6%a $2.9 million reduction in MTC and 4.5%, respectively, inSBC revenues. The distribution revenue reduction was primarily due to lower KWH throughput partially offset by higher composite unit prices resulting from a distribution rate increase pursuant to the stipulated settlements approved by the NJBPU on May 25, 2005. While distribution KWH deliveries declined for the first six months of 2005. Industrial sales decreased by $0.42006 as compared to the previous year, the impact of a full six months of 2006 of the distribution rate increase caused revenues to increase $4.2 million. Wires revenue increased $13.3 million while the MTC and SBC revenues declined $9.1 million. Other revenues declined $3.6 million in the second quarter and $6$1.8 million in the first six months of 2005 reflecting the effect of 3.4% and 20.3% declines in KWH sales, respectively.
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 2006 (see Outlook - Regulatory Matters). Higher unit prices resulted from the BGS auction. The increase in total retail generation KWH sales reduced energy available for sale in the wholesale market which resulted in lower wholesale sales revenues of $4 million in the second quarter of 2005 and $8 million in the first six months of 2005 as compared to the respectivecomparable periods in 2004.
Distribution revenues increased by $22 million in the second quarter and $34 million in the first six months of 2005 as compared to the same periods of 2004, due to higher composite unit prices, caused in part by the June 1, 2005 rate increase, and increased KWH sales to the residential and commercial sectors. The increase in distribution revenues from the industrial sector was partially offset by decreases in KWH sales.reduced transmission revenues.
Operating revenues also reflected a $2 million payment received in the first six months 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 and are credited to JCP&L’s customers, resulting in no impact to current earnings.
Changes in kilowatt-hourKWH sales by customer class in the second quarter and in the first six months of 20052006 compared to the same periods of 20042005 are summarized in the following table:
| | | Three | | Six | | | Three | | Six | | Changes in KWH Sales | | Months | | Months | | | Months | | Months | | Increase (Decrease) | | | | | | | | | | | | Electric Generation: | | | | | | | | | | | | Retail | | | 13.5 | % | | 10.9 | % | | | (3.3) | % | | (1.4) | % | | Wholesale | | | (15.0 | )% | | (15.2 | )% | | | 2.2 | % | | 1.1 | % | Total Electric Generation Sales | | | 6.2 | % | | 4.2 | % | | | (2.1) | % | | (0.9) | % | | | | | | | | | | | | | | | | | | Distribution Deliveries: | | | | | | | | | | | | | | | | Residential | | | 5.1 | % | | 2.2 | % | | | (5.3) | % | | (4.7) | % | | Commercial | | | 2.5 | % | | 3.2 | % | | | (0.3) | % | | (0.7) | % | | Industrial | | | (4.2 | )% | | (2.2 | )% | | | (6.5) | % | | (6.8) | % | Total Distribution Deliveries | | | 2.7 | % | | 2.0 | % | | | (3.2) | % | | (3.3) | % | | | | | | | | | | | | | | | | |
Operating Expenses and Taxes
Total operating expenses and taxes increased $26 million and $55by $37.1 million in the second quarter and $57.0 million in the first six months of 2005, respectively,2006 as compared to the same periods of the prior year. The following table presents changes from the prior year by expense category.category:
| | | Three | | Six | | | Three | | Six | | Operating Expenses and Taxes - Changes | | Months | | Months | | | Expenses - Changes | | | Months | | Months | | | | | (In millions) | | | (In millions) | | Increase (Decrease) | | | | | | | | | | | | Purchased power costs | | $ | 36 | | $ | 42 | | | $ | 21.7 | | $ | 60.2 | | | Other operating costs | | | (1 | ) | | 14 | | | | (8.1 | ) | | (26.2 | ) | | Provision for depreciation | | | - | | 2 | | | | 1.0 | | | 1.4 | | | Amortization of regulatory assets | | | 3 | | 6 | | | | (4.7 | ) | | (6.4 | ) | | Deferral of new regulatory assets | | | (28 | ) | | (28 | ) | | | 27.8 | | | 27.8 | | | Income taxes | | | 16 | | | 19 | | | Net increase in operating expenses and taxes | | $ | 26 | | $ | 55 | | | | General Taxes | | | | (0.6 | ) | | 0.2 | | Net increase in expenses | | | $ | 37.1 | | $ | 57.0 | | | | | | | | | | | | | | | | |
As the result of higher KWH purchases to supply the increased retail generation sales, purchasedPurchased power costs increased by $36$21.7 million in the second quarter of 2006 and $60.2 million in the first six months compared to the same periods of 2005. The increase reflected higher unit prices resulting from the 2006 and 2005 BGS auctions. The change in the deferral of new regulatory assets of $27.8 million in both periods was due to the absence of a 2005 deferral of reliability expenses reflecting a May 2005 NJBPU rate decision. Other operating costs declined $8.1 million in the second quarter and $42$26.2 million for the first six months of 2006 due in part to the absence of costs related to the JCP&L labor strike in 2005. Amortization of regulatory assets decreased $4.7 million in the second quarter and $6.4 million in the first six months of 2005 as2006 due to a reduction in the level of MTC revenue recovery.
Miscellaneous income increased $2.3 million in the second quarter of 2006 and $5.6 million in the first six months compared to the same periods in 2004. Other operating costs decreased $1 million in the second quarter of 2005, but increased $14 million in the first six months of 2005 compared to the same periods of 2004, reflecting in part the effects of a JCP&L labor strike.2005. The JCP&L labor strike, which affected approximately 1,300 employees, began on December 8, 2004 and lasted until March 15, 2005.
Deferral of new regulatory assets decreased expenses by $28 millionincreases in both the second quarter and the first six months of 2005, reflecting NJBPU’s (see Regulatory Matters) approvalperiods is attributed to defer $28 million of previously incurred reliability expenses. Amortization of regulatory assets increased $3 million in the second quarter and $6 million in the first six months of 2005 due to an increase in the level of MTC revenue recovery.income received from customer requested service projects.
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 June 30, 2005,2006, JCP&L had $412,000$95,000 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 second quarter and infirst six months of 2006 compared with the first six months of 2005 compared with 2004, were as follows:
| | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | Operating Cash Flows | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In millions) | | | | | | | | | | | | | Cash earnings (*) | | $ | 65 | | $ | 66 | | $ | 103 | | $ | 113 | | | Working capital and other | | | (6 | ) | | (13 | ) | | 54 | | | 62 | | | Total cash flows from operating activities | | $ | 59 | | $ | 53 | | $ | 157 | | $ | 175 | | | | | | | | | | | | | | | | | (*) Cash earnings is a non-GAAP measure (see reconciliation below). | | | | | | | | | |
| | | Six Months Ended | | | | | | June 30, | | | Operating Cash Flows | | 2006 | | 2005 | | | | | | | (In millions) | | | Cash earnings (1) | | $ | 120 | | $ | 101 | | | | Working capital and other | | | (218 | ) | | 56 | | | | Net cash provided from operating activities | | $ | (98 | ) | $ | 157 | | | | | | | | | | | | | (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. JCP&L believes that cash earnings isare a useful financial measuresure 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 | | Six Months Ended | | | Six Months Ended | | | | | June 30, | | June 30, | | | June 30, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | | | | | | | | | | | | | | (In millions) | | | Net income (GAAP) | | $ | 55 | | $ | 37 | | $ | 70 | | $ | 50 | | | $ | 74 | | $ | 68 | | | Non-cash charges (credits): | | | | | | | | | | | | | | | | | | | Provision for depreciation | | | 20 | | 19 | | 40 | | 38 | | | | 41 | | | 40 | | | Amortization of regulatory assets | | | 71 | | 68 | | 139 | | 132 | | | | 132 | | | 139 | | | Deferral of new regulatory assets | | | (28 | ) | | - | | (28 | ) | | - | | | | - | | | (28 | ) | | Deferred purchased power and other costs | | | (53 | ) | | (40 | ) | | (126 | ) | | (78 | ) | | | (135 | ) | | (126 | ) | | Deferred income taxes | | | 9 | | (20 | ) | | 16 | | (20 | ) | | | 11 | | | 16 | | | Other non-cash items | | | (9 | ) | | 2 | | | (8 | ) | | (9 | ) | | | (3 | ) | | (8 | ) | | Cash earnings (Non-GAAP) | | $ | 65 | | $ | 66 | | $ | 103 | | $ | 113 | | | $ | 120 | | $ | 101 | | | | | | | | | | | | | | | | | | | | |
The $1$19 million and $10 million decreaseincrease in cash earnings foris described under “Results of Operations.” The $274 million decrease from working capital changes primarily resulted from a $109 million change in cash collateral from suppliers, changes in prepayments of $32 million, accrued taxes of $67 million and receivables of $38 million. In the second quarter andyear 2005, JCP&L received cash collateral payments from its suppliers of $135 million. During the first six months of 2005 is described above and under "Results of Operations". The $72006, JCP&L returned $109 million increase for the second quarter and the $8 million decrease for the first six months of 2005 from working capital primarily resulted from changes in receivables.back to its suppliers.
Cash Flows From Financing Activities
Net cash used forprovided from financing activities was $5$201 million in the second quarter of 2005 compared to $1 million in the second quarter of 2004. The increase resulted primarily from an increase in common stock dividends to FirstEnergy. Net cash used for financing activities was $73 million for the first six months of 2005 and $90 million for the same period of 2004. The $17 million reduction resulted from a $37 million decrease in net debt redemptions, partially offset by a $20 million increase in common stock dividends to FirstEnergy. JCP&L retired $63 million of First Mortgage Bonds, Medium Term Notes and Secured Transition Bonds in the first six months of 2006 as compared to net cash used of $73 million in same period of 2005. The change resulted from a $200 million issuance of long-term debt, a $153 million increase in short-term borrowings and a $15 million reduction in common stock dividend payments to FirstEnergy, partially offset by $94 million of additional debt redemptions in the first six months of 2006.
JCP&L had approximately $412,000$28 million of cash and temporary investments (which includes short-term notes receivable from associated companies) and $279approximately $365 million of short-term indebtedness as of June 30, 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 $1.521 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 June 30, 2005,2006, JCP&L had the capability to issue $597$610 million of additional senior notes based upon FMB collateral. BasedAs of June 30, 2006, based upon applicable earnings coverage tests and its charter, JCP&L could issue $866 million$1.3 billion of preferred stock (assuming no additional debt was issued) as of June 30, 2005..
On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. 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 termination date, as the same may be extended. JCP&L’s borrowing limit under the facility is $425 million.
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 was 2.93% in the second quarter of 2005 and 2.79% in the first six months of 2005.2006 was 4.86%.
JCP&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 June 30, 2006, JCP&L's debt to total capitalization as defined under the revolving credit facility was 29%.
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&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 June 30, 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 positive. On June 8, 2006, the NJBPU approved JCP&L’s request to issue securitization bonds associated with BGS stranded cost deferrals. On August 4, 2006, JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, secured pricing on the issuance of $182 million of transition bonds with a weighted average interest rate of 5.5%. As required by the Electric Discount and Energy Competition Act of 1999, as amended. JCP&L will use the proceeds it receives from the issuer principally to reduce stranded costs, including basic generation transition costs, through the retirement of debt, including short-term debt, or equity or both, and also to pay related expenses.
On May 16, 2005, S&P affirmed its 'BBB-' corporate credit ratings on FirstEnergy Corp. and its units and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmation and outlook revision reflects the successful restart12, 2006, JCP&L issued $200 million of 6.40% secured Senior Notes due 2036. The proceeds of the three nuclear units from their respective outages that occurred during the first halfoffering were used to repay at maturity $150 million aggregate principal amount of 2005. S&P noted that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projectedJCP&L’s 6.45% Senior Notes due May 15, 2006 and as the nuclear operations further stabilize.for general corporate purposes.
On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s rating outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in its outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.
Cash Flows From Investing Activities
Net cash used for investing activities was $54$103 million in the second quarter and $83 million for the first six months of 20052006 compared to $52$83 million and $85in the previous year. The $20 million for the same periodschange primarily resulted from increases of 2004. JCP&L’s capital spending for the period 2005-2007 is expected to be about $511$8 million forin property additions for distribution system reliability initiatives and $9 million of which approximately $183 million appliesloans to 2005. associated companies.
During the last two quartershalf of 2005,2006, capital requirements for property additions and improvements are expected to be about $100$72 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 2006-2010 is expected to be approximately $912 million for property additions, of which approximately $162 million applies to 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. The committee isThey are responsible for promoting the effective design and implementation of sound risk management programs. The committeeThey also overseesoversee 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 June 30, 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 changes in the fair value of commodity derivative contracts with a fair value of $14 million. A decrease of $1 million inrelated to energy production during the value of this asset was recorded in thesecond quarter and first six months of 2005 as a decrease2006 are summarized in a regulatory liability, and therefore, had no impact on net income.the following table:
| | | Three Months Ended | | Six Months Ended | | Increase (Decrease) in the Fair Value | | June 30, 2006 | | June 30, 2006 | | of Commodity Derivative Contracts | | Non-Hedge | | Hedge | | Total | | Non-Hedge | | Hedge | | Total | | | | | (In millions) | | Change in the Fair Value of | | | | | | | | | | | | | | Commodity Derivative Contracts: | | | | | | | | | | | | | | | Outstanding net liability at beginning of period | | $ | (1,173 | ) | $ | - | | $ | (1,173 | ) | $ | (1,223 | ) | $ | - | | $ | (1,223 | ) | | New contract value when entered | | | - | | | - | | | - | | | - | | | - | | | - | | | Additions/change in value of existing contracts | | | (15 | ) | | - | | | (15 | ) | | (30 | ) | | - | | | (30 | ) | | Change in techniques/assumptions | | | - | | | - | | | - | | | - | | | - | | | - | | | Settled contracts | | | 76 | | | - | | | 76 | | | 141 | | | - | | | 141 | | Net Liabilities - Derivative Contracts at End of Period (1) | | $ | (1,112 | ) | $ | - | | $ | (1,112 | ) | $ | (1,112 | ) | $ | - | | $ | (1,112 | ) | | | | | | | | | | | | | | | | | | | | | | Impact of Changes in Commodity Derivative Contracts(2) | | | | | | | | | | | | | | | | | | | | | Income Statement effects (pre-tax) | | $ | (1 | ) | $ | - | | $ | (1 | ) | $ | (1 | ) | $ | - | | $ | (1 | ) | | Balance Sheet effects: | | | | | | | | | | | | | | | | | | | | | Regulatory assets (net) | | $ | (62 | ) | $ | - | | $ | (62 | ) | $ | (112 | ) | $ | - | | $ | (112 | ) | | | | | | | | | | | | | | | | | | | | | |
(1)Includes $1,112 million of non-hedge commodity derivative contracts (primarily with NUGs), that 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 June 30, 2006 as follows:
Balance Sheet Classification | | Non-Hedge | | Hedge | | Total | | | | | (In millions) | | Non-Current- | | | | | | | | | | | | Other deferred charges | | | 11 | | | - | | | 11 | | | Other noncurrent liabilities | | | (1,123 | ) | | - | | | (1,123 | ) | | | | | | | | | | | | | Net liabilities | | $ | (1,112 | ) | $ | - | | $ | (1,112 | ) |
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, JCP&L relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of June 30, 20052006 are summarized by year in the following table:
Source of Information | | | | | | | | | | | | | | | | | Fair Value by Contract Year | | 2006(1) | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter | | Total | | | | | (In millions) | | Other external sources (2) | | $ | (147) | | | (257) | | | (226) | | | - | | | - | | | - | | | (630) | | | Prices based on models | | | - | | | - | | | - | | | (168) | | | (144) | | | (170) | | | (482) | | | | | | | | | | | | | | | | | | | | | | | | | | Total(3) | | $ | (147) | | $ | (257) | | $ | (226) | | $ | (168) | | $ | (144) | | $ | (170) | | $ | (1,112) | |
(1)For the last two quarters of 2006. (2)Broker quote sheets. (3)Includes $1,112 million of non-hedge commodity derivative contracts (primarily with NUGs), that are offset by a regulatory asset and does not affect earnings.
Sources of Information - | | | | | | | | | | | | | | | | Fair Value by Contract Year | | | | 2005(1) | | 2006 | | 2007 | | 2008 | | Thereafter | | Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | External sources (2) | | | | | $ | 3 | | $ | 2 | | $ | 2 | | $ | - | | $ | - | | $ | 7 | | | Prices based on models | | | | | | - | | | - | | | - | | | 2 | | | 5 | | | 7 | | | Total | | | | | $ | 3 | | $ | 2 | | $ | 2 | | $ | 2 | | $ | 5 | | $ | 14 | | | | | | | | | | | | | | | | | | | | | | | | | | (1) For the last two quarters of 2005. | | | | | | | | | | | | | | | | | | | | | | | (2) Broker quote sheets. | | | | | | | | | | | | | | | | | | | | | | | | | |
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 its 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 June 30, 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 marketfair value of approximately $79$86 million and $80$84 million as of June 30, 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 June 30, 2005.2006.
Regulatory Matters Regulatory assets are costs which have been authorized by the NJBPU 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. 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 $2.1 billion as of June 30, 2005 and December 31, 2004 were $2.1 billion2006 and $2.2 billion respectively.as of December 31, 2005.
The 2003 NJBPU decision on 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 June 30, 2006, the accumulated deferred cost balance totaled approximately $638 million. New Jersey law allows for securitization of JCP&L's base electricdeferred 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 June 8, 2006, the NJBPU approved JCP&L’s request to issue securitization bonds associated with BGS stranded cost deferrals. On August 4, 2006, JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, secured pricing on the issuance of $182 million of transition bonds with a weighted average interest rate of 5.5%.
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 23, 2006, JCP&L filed updated data reflecting actual amounts through December 31, 2005 of $154 million of costs incurred since July 31, 2003. On March 29, 2006, a pre-hearing conference was held with the presiding ALJ. A schedule for the proceeding orderedwas established, including a discovery period and evidentiary hearings scheduled for September 2006. An NJBPU Decision and Order approving a Phase II proceeding in whichStipulation 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 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 last of the quarterly reliability reports was submitted on June 12, 2006. As of June 30, 2006, there were no performance penalties issued by the NJBPU. In a reaction to the higher closing prices of the 2006 BGS fixed rate auction, the NJBPU, would review whether JCP&L is in compliance with current service reliabilityon March 16, 2006, initiated a generic proceeding to evaluate the auction process and quality standards and determine whetherpotential options for the expenditures and projects undertaken by JCP&L to increase its system's reliability are prudent and reasonable for rate recovery. Dependingfuture. On April 6, 2006, initial comments were submitted. A public meeting was held on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an interim motionApril 21, 2006 and a supplemental and amended motion for rehearing and reconsideration of the 2003 NJBPU decision, respectively.legislative-type hearing was held on April 28, 2006. 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 requested an increase to the MTC deferred balance recovery of approximately $20 million annually.
On May 25, 2005,June 21, 2006, the NJBPU approved two stipulated settlement agreements. The first stipulation between JCP&L and the NJBPU staff resolves all of the issues associated with JCP&L's motion for reconsideration of the 2003 NJBPU order (Phase I Order). The second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase II proceeding. The stipulated settlements provide for, among other things, the following:
| · | An annual increase in distribution revenues of $23 million effective June 1, 2005, associated with the Phase I Order reconsideration; |
| · | An annual increase in distribution revenues of $36 million effective June 1, 2005, related to JCP&L's Phase II Petition; |
| · | An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its BGS/MTC deferred cost balance; |
| · | An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and |
| · | A commitment by JCP&L to maintain a target level of customer service reliability with a reduction in JCP&L's authorized return on common equity to its previous level of 9.5% after the target is not met for two consecutive quarters. The authorized return on common equity would then be restored to 9.75% when the target is met for two consecutive quarters. |
The Phase II stipulation included an agreement that the distribution revenues increase reflects a three-year amortization of JCP&L's service reliability improvement costs incurred in 2003-2005. This resulted in the creationcontinued use of a regulatory asset associated with the accelerated reliability costs which were expensed in 2003 and 2004. The establishment of the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million in the second quarter of 2005.
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 NJBPU order. New BGS tariffs reflecting the results of a February 2005descending block auction for the BGS supply became effective June 1, 2005. On May 5, 2005,Fixed Price Residential Class. A final decision as to the NJBPU issued an order that BGS procurement proposals for post transition year four be filed by July 1, 2005. The NJBPU requested that the filings address transmission rate issues and rate design alternatives. JCP&L filed its proposal on July 1, 2005. The next auction is scheduled to take place in February 2006method for the supply period beginning June 1,Commercial Industrial Energy Price Class is expected in October 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 Jerseyits 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 repeal of PUHCA pursuant to 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 JCP&L's service reliability. Onbusinesses unrelated to the utility industry. A public hearing was held on February 7, 2006 and comments were submitted to the NJBPU. The NJBPU Staff issued a draft proposal on March 29, 2004,31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU adoptedStaff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. Comments on the alternative proposal were submitted on June 15, 2006. JCP&L is unable to predict the outcome of this proceeding.
On December 21, 2005, the NJBPU initiated a Memorandum of Understanding (MOU) that set out specific tasksgeneric proceeding and requested comments in order to formulate an appropriate regulatory treatment for investment tax credits related to service reliability to be performedgeneration assets divested by New Jersey’s four electric utility companies. Comments were filed by the utilities and by the DRA. JCP&L and a timetable for completion and endorsed JCP&L's ongoing actions to implementwas advised by the MOU.IRS on April 10, 2006 that the ruling was tentatively adverse. On June 9, 2004,April 28, 2006, the NJBPU approveddirected JCP&L to withdraw its request for a Stipulation that incorporatesprivate letter ruling on this issue, which had been previously filed with the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability andIRS as ordered by the Executive Summary and Recommendation portions of the final report ofNJBPU. On May 11, 2006, after 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&L Motion for Reconsideration was issueddenied by the NJBPU, on July 23, 2004. On February 11, 2005, JCP&L met withfiled to withdraw the Ratepayer Advocaterequest for a private letter ruling. On July 19, 2006, the IRS acknowledged that the JCP&L ruling request was withdrawn. On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to discuss reliability improvements.submit compliance filings containing a SECA mechanism 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, continuesMet-Ed, Penelec, and FES continue to file compliance reports reflecting activities associated withbe involved in the MOUFERC hearings concerning the calculation and Stipulation.imposition of the SECA charges. The hearing was held in May 2006. Initial briefs were submitted on June 9, 2006 and reply briefs were filed on June 27, 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, was a partyMet-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 referralrefund 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. Hearings in the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate. The ALJ recommended an April 1, 2006 effective date for this change in rate design. If the FERC accepts this recommendation, the transmission rate applicable to many load zones in PJM would increase. FirstEnergy believes that significant additional transmission revenues would have to be recovered from the JCP&L, Met-Ed and Penelec transmission zones within PJM. The Companies, as part of the Responsible Pricing Alliance, intend to submit a brief on exceptions within thirty days of the initial decision. Following submission of reply exceptions, the case is expected to be reviewed by the FERC with a decision anticipated in the fourth quarter of 2006.
See Note 1411 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.
Environmental Matters
JCP&L accrues environmental liabilities 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 June 30, 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 $54.7 million have been accrued liabilities aggregating approximately $47 million as ofthrough June 30, 2005.2006.
FirstEnergy plansSee Note 10(B) to issuethe consolidated financial statements for further details and a report that will disclose the Companies’complete discussion of 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.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 Note 10(C) to the consolidated financial statements. 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 Division 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 Division. 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 June 30, 2005.
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 websiteWeb site (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. FirstEnergy is also is proceeding with the implementation of the 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 new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, thatequipment. The 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 FirstEnergy’s 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.
Three substantially similar actions were filed in various Ohio State courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All three cases were dismissed for lack of jurisdiction and further appeals were unsuccessful. Two of these cases were refiled at the PUCO, one in 2004 and another in 2005. In each, individual complainants—three in one case and four in the other—seek damages related to the outages and also seek to represent others as part of a class action. FirstEnergy has filed responsive pleadings to both cases. The PUCO has dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Both cases are otherwise currently pending further proceedings. In addition to the two cases that were refiled at the PUCO, the Ohio Companies wereabove proceedings, FirstEnergy was named as respondents in a regulatory proceeding thatcomplaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. FirstEnergy's motion to dismiss the matter was initiated atdenied on June 2, 2006. FirstEnergy has since filed an appeal, which is pending. A responsive pleading to this matter has been filed. Also, the PUCOcomplaint has been amended to include an additional party. No estimate of potential liability has been undertaken in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages.this matter.
FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy were based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. The plaintiff has not appealed.
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. 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
FSP FIN 46(R)-6 - “Determining the Variability to Be Considered in Applying FASB interpretation No. 46(R)”
In April 2006, the FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should determine the variability to be considered in applying FASB interpretation No. 46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the first quarter of 2004, consolidating VIE’s when FirstEnergy or one of its subsidiaries is determined to be the VIE’s primary beneficiary. The variability that is considered in applying interpretation 46(R) affects the determination of (a) whether the entity is a VIE; (b) which interests are variable interests in the entity; and (c) which party, if any, is the primary beneficiary of the VIE. This FSP states that the variability to be considered shall be based on an analysis of the design of the entity, involving two steps:
| Step 1: | Analyze the nature of the risks in the entity | | | SFAS 154 - "Accounting Changes
| | Step 2: | Determine the purpose(s) for which the entity was created and Error Corrections - a replacement of APB Opinion No. 20determine the variability the entity is designed to create and FASB Statement No. 3"pass along to its interest holders. |
In May 2005,After determining the FASB issued SFAS 154variability to changeconsider, the requirements for accounting and reporting a changeenterprise can determine which interests are designed to absorb that variability. The guidance in accounting principle. It appliesthis FSP is applied prospectively to all voluntary changes in accounting principleentities (including newly created entities) with which that enterprise first becomes involved and to changesall entities previously required by an accounting pronouncementto be analyzed under interpretation 46(R) when that pronouncementa reconsideration event has occurred after July 1, 2006. JCP&L does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances,expect this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and thathave a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement ofmaterial impact on its financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. JCP&L will adopt this standard effective January 1, 2006.statements.
FIN 47, "Accounting48 - “Accounting for Conditional Asset Retirement ObligationsUncertainty in Income Taxes - an interpretation of FASB Statement No. 143"109.”
On March 30, 2005,In June 2006, the FASB issued FIN 4748 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to clarifybe taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation will be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the scope and timingmore likely than not recognition threshold to determine the amount of liability recognition for conditional asset retirement obligations. Under this Interpretation, companies are requiredbenefit 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.financial statements. This Interpretationinterpretation is effective no later than the end offor fiscal years endingbeginning after December 15, 2005. Therefore, JCP&L will adopt this Interpretation in the fourth quarter of 2005.2006. JCP&L is currently evaluating the effectimpact of this Interpretation will have on its financial statements.Statement.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"SUBSEQUENT EVENTS
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 indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, JCP&L continues to evaluate its investments as required by existing authoritative guidance.New Jersey Law Change
On July 8, 2006, the Governor of New Jersey signed tax legislation that increased the current New Jersey Corporate Business tax by an additional 4% surtax, which increases the effective tax from 9% to 9.36%. This increase applies to JCP&L’s 2006 through 2008 tax years and is not expected to have a material impact on JCP&L’s results of operations.
METROPOLITAN EDISON COMPANY | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In thousands) | | | | | | | | | | | | | OPERATING REVENUES | | $ | 263,136 | | $ | 242,044 | | $ | 558,917 | | $ | 502,942 | | | | | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | Purchased power | | | 131,670 | | | 131,266 | | | 281,763 | | | 274,722 | | | Other operating costs | | | 52,648 | | | 47,021 | | | 111,118 | | | 80,069 | | | Provision for depreciation | | | 11,377 | | | 9,824 | | | 22,898 | | | 19,722 | | | Amortization of regulatory assets | | | 25,286 | | | 22,949 | | | 53,907 | | | 48,446 | | | General taxes | | | 17,023 | | | 16,687 | | | 36,295 | | | 34,423 | | | Income taxes | | | 5,133 | | | 751 | | | 11,865 | | | 8,731 | | | Total operating expenses and taxes | | | 243,137 | | | 228,498 | | | 517,846 | | | 466,113 | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 19,999 | | | 13,546 | | | 41,071 | | | 36,829 | | | | | | | | | | | | | | | | | OTHER INCOME (net of income taxes) | | | 6,989 | | | 6,116 | | | 13,438 | | | 11,642 | | | | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | | | | Interest on long-term debt | | | 9,385 | | | 12,238 | | | 18,945 | | | 22,385 | | | Allowance for borrowed funds used during construction | | | (73 | ) | | (72 | ) | | (251 | ) | | (143 | ) | | Other interest expense | | | 2,013 | | | 831 | | | 3,676 | | | 1,520 | | | Net interest charges | | | 11,325 | | | 12,997 | | | 22,370 | | | 23,762 | | | | | | | | | | | | | | | | | NET INCOME | | | 15,663 | | | 6,665 | | | 32,139 | | | 24,709 | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | Unrealized gain (loss) on derivative hedges | | | 84 | | | (6 | ) | | 168 | | | (3,266 | ) | | Unrealized loss on available for sale securities | | | - | | | (75 | ) | | - | | | (53 | ) | | Other comprehensive income (loss) | | | 84 | | | (81 | ) | | 168 | | | (3,319 | ) | | Income tax (benefit) related to other comprehensive income | | | 35 | | | (37 | ) | | 70 | | | (28 | ) | | Other comprehensive income (loss), net of tax | | | 49 | | | (44 | ) | | 98 | | | (3,291 | ) | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 15,712 | | $ | 6,621 | | $ | 32,237 | | $ | 21,418 | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of | | | these statements. | | | | | | | | | | | | | |
METROPOLITAN EDISON COMPANY | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | (Unaudited) | | | | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2006 | | 2005 | | 2006 | | 2005 | | | | | (In thousands) | | | | | | | | | | | | | REVENUES | | $ | 282,219 | | $ | 263,136 | | $ | 593,432 | | $ | 558,917 | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | Purchased power | | | 143,070 | | | 131,670 | | | 302,957 | | | 281,763 | | | Other operating costs | | | 59,575 | | | 52,648 | | | 120,654 | | | 111,118 | | | Provision for depreciation | | | 10,288 | | | 11,377 | | | 21,193 | | | 22,898 | | | Amortization of regulatory assets | | | 25,669 | | | 25,286 | | | 55,717 | | | 53,907 | | | Deferral of new regulatory assets | | | (45,581 | ) | | - | | | (45,581 | ) | | - | | | General taxes | | | 18,595 | | | 17,023 | | | 39,216 | | | 36,295 | | | Total expenses | | | 211,616 | | | 238,004 | | | 494,156 | | | 505,981 | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 70,603 | | | 25,132 | | | 99,276 | | | 52,936 | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | Interest income | | | 8,964 | | | 9,442 | | | 17,714 | | | 18,469 | | | Miscellaneous income | | | 1,792 | | | 3,288 | | | 4,404 | | | 4,429 | | | Interest expense | | | (12,071 | ) | | (11,398 | ) | | (23,255 | ) | | (22,621 | ) | | Capitalized interest | | | 344 | | | 73 | | | 611 | | | 251 | | | Total other income (expense) | | | (971 | ) | | 1,405 | | | (526 | ) | | 528 | | | | | | | | | | | | | | | | | INCOME TAXES | | | 29,555 | | | 10,874 | | | 40,759 | | | 21,325 | | | | | | | | | | | | | | | | | NET INCOME | | | 40,077 | | | 15,663 | | | 57,991 | | | 32,139 | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME: | | | | | | | | | | | | | | | Unrealized gain on derivative hedges | | | 84 | | | 84 | | | 168 | | | 168 | | | Income tax expense related to other comprehensive income | | | 35 | | | 35 | | | 70 | | | 70 | | | Other comprehensive income, net of tax | | | 49 | | | 49 | | | 98 | | | 98 | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 40,126 | | $ | 15,712 | | $ | 58,089 | | $ | 32,237 | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements. |
METROPOLITAN EDISON COMPANY | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | | | | | | | | June 30, | | December 31, | | | | | 2006 | | 2005 | | | | | (In thousands) | | ASSETS | | | | | | CURRENT ASSETS: | | | | | | | | | Cash and cash equivalents | | $ | 134 | | $ | 120 | | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $4,069,000 and $4,352,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 128,349 | | | 129,854 | | | Associated companies | | | 1,881 | | | 37,267 | | | Other | | | 7,489 | | | 8,780 | | | Notes receivable from associated companies | | | 31,921 | | | 27,867 | | | Prepaid gross receipts taxes | | | 25,361 | | | 2,072 | | | Prepayments and other | | | 7,115 | | | 5,840 | | | | | | 202,250 | | | 211,800 | | UTILITY PLANT: | | | | | | | | | In service | | | 1,885,164 | | | 1,856,425 | | | Less - Accumulated provision for depreciation | | | 723,799 | | | 721,566 | | | | | | 1,161,365 | | | 1,134,859 | | | Construction work in progress | | | 20,737 | | | 20,437 | | | | | | 1,182,102 | | | 1,155,296 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 243,179 | | | 234,854 | | | Other | | | 1,367 | | | 1,453 | | | | | | 244,546 | | | 236,307 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 860,485 | | | 864,438 | | | Regulatory assets | | | 358,963 | | | 309,556 | | | Prepaid pension costs | | | 92,472 | | | 89,005 | | | Other | | | 47,673 | | | 51,285 | | | | | | 1,359,593 | | | 1,314,284 | | | | | $ | 2,988,491 | | $ | 2,917,687 | | LIABILITIES AND CAPITALIZATION | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 150,000 | | $ | 100,000 | | | Short-term borrowings- | | | | | | | | | Associated companies | | | 72,540 | | | 140,240 | | | Other | | | 66,000 | | | - | | | Accounts payable- | | | | | | | | | Associated companies | | | 18,134 | | | 37,220 | | | Other | | | 52,754 | | | 27,507 | | | Accrued taxes | | | 5,866 | | | 17,911 | | | Accrued interest | | | 9,735 | | | 9,438 | | | Other | | | 21,539 | | | 24,274 | | | | | | 396,568 | | | 356,590 | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity- | | | | | | | | | Common stock, without par value, authorized 900,000 shares- | | | | | | | | | 859,000 shares outstanding | | | 1,283,182 | | | 1,287,093 | | | Accumulated other comprehensive loss | | | (1,471 | ) | | (1,569 | ) | | Retained earnings | | | 88,566 | | | 30,575 | | | Total common stockholder's equity | | | 1,370,277 | | | 1,316,099 | | | Long-term debt and other long-term obligations | | | 541,948 | | | 591,888 | | | | | | 1,912,225 | | | 1,907,987 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 369,737 | | | 344,929 | | | Accumulated deferred investment tax credits | | | 9,643 | | | 10,043 | | | Nuclear fuel disposal costs | | | 40,444 | | | 39,567 | | | Asset retirement obligation | | | 146,493 | | | 142,020 | | | Retirement benefits | | | 57,118 | | | 57,809 | | | Other | | | 56,263 | | | 58,742 | | | | | | 679,698 | | | 653,110 | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | $ | 2,988,491 | | $ | 2,917,687 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these balance sheets. |
| | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | Six Months Ended | | | | June 30, | | | | 2006 | | 2005 | | | | (In thousands) | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | Net income | | $ | 57,991 | | $ | 32,139 | | | Adjustments to reconcile net income to net cash from operating activities - | | | | | | | | | Provision for depreciation | | | 21,193 | | | 22,898 | | | Amortization of regulatory assets | | | 55,717 | | | 53,907 | | | Deferred costs recoverable as regulatory assets | | | (50,570 | ) | | (47,798 | ) | | Deferral of new regulatory assets | | | (45,581 | ) | | - | | | Deferred income taxes and investment tax credits, net | | | 22,463 | | | (1,898 | ) | | Accrued compensation and retirement benefits | | | (4,712 | ) | | (4,519 | ) | | Cash collateral to suppliers | | | (2,250 | ) | | - | | | Decrease (increase) in operating assets - | | | | | | | | | Receivables | | | 38,182 | | | 110,210 | | | Prepayments and other current assets | | | (24,564 | ) | | (21,205 | ) | | Increase (decrease) in operating liabilities - | | | | | | | | | Accounts payable | | | 6,161 | | | (50,593 | ) | | Accrued taxes | | | (12,045 | ) | | (5,184 | ) | | Accrued interest | | | 297 | | | (887 | ) | | Other | | | (4,011 | ) | | 1,424 | | | Net cash provided from operating activities | | | 58,271 | | | 88,494 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | - | | | - | | | Short-term borrowings, net | | | - | | | 20,931 | | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | - | | | (37,830 | ) | | Short-term borrowings, net | | | (1,707 | ) | | - | | | Dividend Payments- | | | | | | | | | Common stock | | | - | | | (34,000 | ) | | Net cash used for financing activities | | | (1,707 | ) | | (50,899 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (47,301 | ) | | (34,395 | ) | | Proceeds from nuclear decommissioning trust fund sales | | | 116,704 | | | 55,081 | | | Investments in nuclear decommissioning trust funds | | | (121,446 | ) | | (59,823 | ) | | Loan repayments from (loans to) associated companies, net | | | (4,054 | ) | | 3,339 | | | Other | | | (453 | ) | | (1,797 | ) | | Net cash used for investing activities | | | (56,550 | ) | | (37,595 | ) | | | | | | | | | | | Net change in cash and cash equivalents | | | 14 | | | - | | | Cash and cash equivalents at beginning of period | | | 120 | | | 120 | | | Cash and cash equivalents at end of period | | $ | 134 | | $ | 120 | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements. |
METROPOLITAN EDISON COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | | | | | | | | June 30, | | December 31, | | | | | 2005 | | 2004 | | | | | (In thousands) | | ASSETS | | | | | | UTILITY PLANT: | | | | | | | In service | | $ | 1,814,049 | | $ | 1,800,569 | | | Less - Accumulated provision for depreciation | | | 704,247 | | | 709,895 | | | | | | 1,109,802 | | | 1,090,674 | | | Construction work in progress | | | 15,716 | | | 21,735 | | | | | | 1,125,518 | | | 1,112,409 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 221,600 | | | 216,951 | | | Long-term notes receivable from associated companies | | | 11,053 | | | 10,453 | | | Other | | | 29,079 | | | 34,767 | | | | | | 261,732 | | | 262,171 | | CURRENT ASSETS: | | | | | | | | | Cash and cash equivalents | | | 120 | | | 120 | | | Notes receivable from associated companies | | | 14,830 | | | 18,769 | | | Receivables - | | | | | | | | | Customers (less accumulated provisions of $4,109,000 and $4,578,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 125,135 | | | 119,858 | | | Associated companies | | | 10,362 | | | 118,245 | | | Other | | | 7,889 | | | 15,493 | | | Prepayments and other | | | 32,262 | | | 11,057 | | | | | | 190,598 | | | 283,542 | | DEFERRED CHARGES: | | | | | | | | | Goodwill | | | 867,649 | | | 869,585 | | | Regulatory assets | | | 673,366 | | | 693,133 | | | Other | | | 24,015 | | | 24,438 | | | | | | 1,565,030 | | | 1,587,156 | | | | | $ | 3,142,878 | | $ | 3,245,278 | | CAPITALIZATION AND LIABILITIES | | | | | | | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity - | | | | | | | | | Common stock, without par value, authorized 900,000 shares - | | | | | | | | | 859,500 shares outstanding | | $ | 1,290,287 | | $ | 1,289,943 | | | Accumulated other comprehensive loss | | | (43,392 | ) | | (43,490 | ) | | Retained earnings | | | 37,106 | | | 38,966 | | | Total common stockholder's equity | | | 1,284,001 | | | 1,285,419 | | | Long-term debt and other long-term obligations | | | 694,122 | | | 701,736 | | | | | | 1,978,123 | | | 1,987,155 | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | | - | | | 30,435 | | | Short-term borrowings - | | | | | | | | | Associated companies | | | 34,021 | | | 80,090 | | | Other | | | 67,000 | | | - | | | Accounts payable - | | | | | | | | | Associated companies | | | 32,941 | | | 88,879 | | | Other | | | 31,442 | | | 26,097 | | | Accrued taxes | | | 6,773 | | | 11,957 | | | Accrued interest | | | 10,731 | | | 11,618 | | | Other | | | 18,106 | | | 23,076 | | | | | | 201,014 | | | 272,152 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 316,005 | | | 305,389 | | | Accumulated deferred investment tax credits | | | 10,456 | | | 10,868 | | | Power purchase contract loss liability | | | 317,602 | | | 349,980 | | | Nuclear fuel disposal costs | | | 38,900 | | | 38,408 | | | Asset retirement obligation | | | 137,074 | | | 132,887 | | | Retirement benefits | | | 79,014 | | | 82,218 | | | Other | | | 64,690 | | | 66,221 | | | | | | 963,741 | | | 985,971 | | COMMITMENTS AND CONTINGENCIES (Note 13) | | | | | | | | | | | $ | 3,142,878 | | $ | 3,245,278 | | | | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral | | | part of these balance sheets. | | | | | | | | | | | | | | | | |
METROPOLITAN EDISON COMPANY | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In thousands) | | | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | Net income | | $ | 15,663 | | $ | 6,665 | | $ | 32,139 | | $ | 24,709 | | | Adjustments to reconcile net income to net cash from | | | | | | | | | | | | | | | operating activities - | | | | | | | | | | | | | | | Provision for depreciation | | | 11,377 | | | 9,824 | | | 22,898 | | | 19,722 | | | Amortization of regulatory assets | | | 25,286 | | | 22,949 | | | 53,907 | | | 48,446 | | | Deferred costs recoverable as regulatory assets | | | (13,571 | ) | | (13,195 | ) | | (30,012 | ) | | (29,987 | ) | | Deferred income taxes and investment tax credits, net | | | (1,887 | ) | | (7,952 | ) | | (1,898 | ) | | (5,519 | ) | | Accrued retirement benefit obligation | | | (1,556 | ) | | (309 | ) | | (3,203 | ) | | 765 | | | Accrued compensation, net | | | 407 | | | 186 | | | (1,316 | ) | | (448 | ) | | Decrease (increase) in operating assets - | | | | | | | | | | | | | | | Receivables | | | 40,498 | | | 26,775 | | | 110,210 | | | 32,542 | | | Materials and supplies | | | - | | | 18 | | | (18 | ) | | 36 | | | Prepayments and other current assets | | | 12,930 | | | 7,293 | | | (21,187 | ) | | (29,325 | ) | | Increase (decrease) in operating liabilities - | | | | | | | | | | | | | | | Accounts payable | | | (1,002 | ) | | (12,169 | ) | | (50,593 | ) | | (5,321 | ) | | Accrued taxes | | | 4,487 | | | (4,564 | ) | | (5,184 | ) | | (6,110 | ) | | Accrued interest | | | 286 | | | 7,344 | | | (887 | ) | | 2,879 | | | Other | | | (7,228 | ) | | 6,040 | | | (16,362 | ) | | (2,225 | ) | | Net cash provided from operating activities | | | 85,690 | | | 48,905 | | | 88,494 | | | 50,164 | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | New Financing- | | | | | | | | | | | | | | | Long-term debt | | | - | | | - | | | - | | | 247,607 | | | Short-term borrowings, net | | | (7,656 | ) | | - | | | 20,931 | | | - | | | Redemptions and Repayments- | | | | | | | | | | | | | | | Long-term debt | | | (37,395 | ) | | (100,000 | ) | | (37,830 | ) | | (150,435 | ) | | Short-term borrowings, net | | | - | | | - | | | - | | | (65,335 | ) | | Dividend Payments- | | | | | | | | | | | | | | | Common stock | | | (25,000 | ) | | (20,000 | ) | | (34,000 | ) | | (25,000 | ) | | Net cash provided from (used for) financing activities | | | (70,051 | ) | | (120,000 | ) | | (50,899 | ) | | 6,837 | | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | Property additions | | | (18,196 | ) | | (12,381 | ) | | (34,395 | ) | | (21,343 | ) | | Contributions to nuclear decommissioning trusts | | | (2,371 | ) | | (2,371 | ) | | (4,742 | ) | | (4,742 | ) | | Loan repayments from (loans to) associated companies, net | | | 6,489 | | | 85,767 | | | 3,339 | | | (31,035 | ) | | Other | | | (1,561 | ) | | 80 | | | (1,797 | ) | | 118 | | | Net cash provided from (used for) investing activities | | | (15,639 | ) | | 71,095 | | | (37,595 | ) | | (57,002 | ) | | | | | | | | | | | | | | | | | Net change in cash and cash equivalents | | | - | | | - | | | - | | | (1 | ) | | Cash and cash equivalents at beginning of period | | | 120 | | | 120 | | | 120 | | | 121 | | | 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 an 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 June 30, 2005,2006, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2006 and 2005 and 2004.the consolidated statement of cash flows for the six-month period ended June 30, 2006 and 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 have 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[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 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 6 tostatements] dated February 27, 2006, we expressed an unqualified opinion on those consolidated financial statements) dated March 7, 2005, 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.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 July 29, 2005August 4, 2006
METROPOLITAN EDISON COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy. Met-Ed 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 income increased to $16 million forin the second quarter of 20052006 increased to $40 million from $7$16 million in the second quarter of 2004.2005. For the first six months of 2005,2006, net income increased to $32$58 million from $25$32 million in the same period of 2004.2005. The increase in net income for both periods reflects higher operating revenues and the deferral of new regulatory assets, partially offset by increased purchased power costs and other income, and lower interest charges. Partially offsetting these items for both periods were increased operating expenses and taxescosts as discussed below.
Operating revenuesRevenues
Revenues increased by $21$19 million, or 8.7%7.3%, in the second quarter of 20052006 and by $56$35 million, or 11.1%6.2%, in the first six months of 2005,2006, compared with the same periods of 2004.2005. Increases in both periods were primarily due in part to higher retail generation electric revenues from all customer sectors ($915 million for the second quarter and $24$27 million for the first six months). The increase in retail generation KWH sales in both periods of 2005 are mainly attributable to weather and lower customer shopping -- primarily in the industrial sector. Shopping by industrial customers decreased by 10.8% and 14.3% in the second quarter and first six months of 2005, respectively. While the higher generation sales in the second quarter were offset by slightly lower composite unit prices, overall which reflected higher composite unit prices in the six-month period further contributedall customer classes. Higher KWH sales to commercial and industrial customers were partially offset by lower KWH sales to residential customers. Industrial KWH sales increased primarily due to the increasereturn of customers to Met-Ed from alternative suppliers. Sales by alternative suppliers as a percent of total industrial sales in generation revenues.Met-Ed’s franchise area decreased by 14.5 percentage points, in the second quarter of 2006 and 14.2 percentage points in the first six months of 2006. For both periods, residential KWH sales decreased primarily due to the milder weather in 2006 compared with 2005.
Revenues from distribution throughput increased by $4$1 million in the second quarter of 2006 compared with the same period of 2005. The increase was due to higher composite unit prices and a 0.4% increase in total KWH deliveries. This relatively flat change in KWH deliveries reflected a 3.2% increase in deliveries to commercial customers primarily due to a 1.7% increase in the number of commercial customers, partially offset by $10milder weather in the second quarter of 2006 (a 21% decrease in heating degree days and an 8.0% decrease in cooling degree days) compared to the same period in 2005. The $1 million decrease in distribution revenues in the first six months of 20052006 was primarily due to a 1.1% decrease in KWH deliveries, reflecting the milder temperatures in 2006 compared withto the respective prior year periods. Both increases weresame period in 2005.
For both periods, transmission revenues increased primarily due to higher KWH deliveries and higher unit prices. Also contributing to the higher operating revenues was an increase in transmission revenues of $6 million in the second quarter and $16 million in the first six months of 2005. This increase was due to a change in the power supply agreement with FES in the second quarter of 2004. That changeprices, which also resulted in higher transmission expenses as discussed further below. Operating revenues also included a $4 million payment received inIn the first six months of 2006, other revenues also increased due to a $2 million increase in the first quarter of 2006, compared to the same period in 2005, for a 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 specificspecified levels, and arewhich occurred. This payment is credited to Met-Ed’s customers, resulting in no net impact to current earnings.earnings effect.
Changes in kilowatt-hourKWH sales by customer class in the second quarter and the first six months of 20052006 compared towith the same periods of 2004in 2005 are summarized in the following table:
| | | Three | | Six | | | Three | | Six | | Changes in KWH Sales | | Months | | Months | | | Months | | Months | | Increase (Decrease) | | | | | | | | | | | | Retail Electric Generation: | | | | | | | | | | | | Residential | | | 5.1 | % | | 3.4 | % | | | (1.0 | )% | | (1.9 | )% | | Commercial | | | 5.6 | % | | 6.3 | % | | | 4.2 | % | | 2.1 | % | | Industrial | | | 13.0 | % | | 21.8 | % | | | 15.8 | % | | 14.0 | % | Total Retail Electric Generation Sales | | | 7.4 | % | | 8.8 | % | | | 5.6 | % | | 3.7 | % | | | | | | | | | | | | | | Distribution Deliveries: | | | | | | | | | | | | Residential | | | 5.0 | % | | 3.4 | % | | | (1.2 | )% | | (2.1 | )% | | Commercial | | | 4.2 | % | | 4.8 | % | | | 3.2 | % | | 1.2 | % | | Industrial | | | (1.2 | )% | | 1.3 | % | | | (0.9 | )% | | (2.3 | )% | Total Distribution Deliveries | | | 2.7 | % | | 3.2 | % | | | 0.4 | % | | (1.1 | | | | | | | | | | | | | | | | |
Expenses Operating Expenses Total expenses decreased by $27 million and Taxes
Total operating expenses and taxes increased by $15$12 million in the second quarter and by $52 million in the first six months of 20052006, respectively, compared with the same periods of 2004.2005. The following table presents changes from the prior year by expense category:
| | | Three | | Six | | | Three | | Six | | Operating Expenses and Taxes - Increases | | Months | | Months | | | | | | (In millions) | | | Expenses - Changes | | | Months | | Months | | Increase (Decrease) | | | (In millions) | | | Purchased power costs | | $ | - | | $ | 7 | | | $ | 11 | | $ | 21 | | | Other operating costs | | | 6 | | | 31 | | | | 7 | | | 10 | | | Provision for depreciation | | | 2 | | | 3 | | | | (1 | ) | | (2 | ) | | Amortization of regulatory assets | | | 2 | | | 6 | | | | - | | 2 | | | Deferral of new regulatory assets | | | | (46 | ) | | (46 | ) | | General taxes | | | 1 | | | 2 | | | | 2 | | | 3 | | | Income taxes | | | 4 | | | 3 | | | Net increase in operating expenses and taxes | | $ | 15 | | $ | 52 | | | | | | | | | | | | | Net decrease in expenses | | | $ | (27 | ) | $ | (12 | ) |
Purchased power costs increased in both second quarter and first six months of 2005 as a result of higher two-party power purchases ($27 million in the second quarter and $45 million in the first six months of 2005) and NUG contract purchases ($6 million in the second quarter and $8 million in the first six months of 2005), offset by a reduction in purchased power from FES ($33 million in the second quarter and $46 million in the first six months of 2005). The net increase in KWH purchases for both periods was required to meet higher retail generation demand.
Other operating costs increased in the second quarter and first six months of 2005 primarily2006 by $11 million and $21 million, respectively, due to increased purchases to meet higher PJM congestion chargescustomer demand and transmission expenses. The transmission expense increase for both periods resulted from the change in the power supply agreement with FES as discussed above.
Depreciation expensehigher composite unit prices. These increases were partially offset by increased NUG cost deferrals of $6 million in the second quarter and first six months of 2005 due to an increase in the asset base. Depreciation expense also increased for the first six months due to higher estimated costs to decommission the Saxton nuclear plant. For both periods of 2005, regulatory asset amortization reflected increases associated with the level of CTC revenue recovery, partially offset by lower amortization related to above market NUG costs as compared to the prior year periods.
General taxes increased $2$4 million in the first six months of 20052006. Other operating costs increased for both periods primarily due to higher transmission expenses, which increased as thea result of the higher transmission prices discussed above. The deferral of new regulatory assets of $46 million reflected the May 4, 2006 PPUC approval of Met-Ed’s request to defer certain 2006 transmission-related costs. Met-Ed implemented the deferral accounting in the second quarter of 2006, which included $24 million for costs incurred in the first quarter of 2006 (see Regulatory Matters for further discussion). For both periods, general taxes increased 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, issuance of long-term debt, and funds from the capital markets.short-term credit arrangements.
Changes in Cash Position
As of June 30, 2005 and December 31, 2004,2006, Met-Ed had $120,000$134,000 of cash and cash equivalents.equivalents compared with $120,000 as of December 31, 2005. The major sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided from operating activities in 2005the first six months of 2006 and 20042005 were as follows:
| | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | Operating Cash Flows | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In millions) | | | | | | | | | | | | | Cash earnings (*) | | $ | 36 | | $ | 19 | | $ | 73 | | $ | 58 | | | Working capital and other | | | 50 | | | 30 | | | 16 | | | (8 | ) | | Total cash flows form operating activities | | $ | 86 | | $ | 49 | | $ | 89 | | $ | 50 | | | | | | | | | | | | | | | | | (*) Cash earnings is a non-GAAP measure (see reconciliation below). | | | | | | | | | | | | | |
| | | Six Months Ended | | | | | June 30, | | Operating Cash Flows | | 2006 | | 2005 | | | | | (In millions) | | Cash earnings (1) | | $ | 56 | | $ | 55 | | | Working capital and other | | | 2 | | | 33 | | | Net cash provided from operating activities | | $ | 58 | | $ | 88 | | | | | | | | | | |
(1) Cash earnings are a non-GAAP measure (see reconciliation below).
Cash earnings (in the table above) isare 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. The following table reconciles cash earnings with net income.
| | | Six Months Ended | | | | | June 30, | | Reconciliation of Cash Earnings | | 2006 | | 2005 | | | | | (In millions) | | | Net income (GAAP) | | $ | 58 | | $ | 32 | | | Non-cash charges (credits): | | | | | | | | | Provision for depreciation | | | 21 | | | 23 | | | Amortization of regulatory assets | | | 56 | | | 54 | | | Deferred costs recoverable as regulatory assets | | | (51 | ) | | (48 | ) | | Deferral of new regulatory assets | | | (46 | ) | | - | | | Deferred income taxes and investment tax credits, net | | | 23 | | | (2 | ) | | Other non-cash charges | | | (5 | ) | | (4 | ) | | Cash earnings (Non-GAAP) | | $ | 56 | | $ | 55 | | | | | | | | | | |
| | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In millions) | | | | | | | | | | | | | | Net income (GAAP) | | $ | 16 | | $ | 7 | | $ | 32 | | $ | 25 | | | Non-cash charges (credits): | | | | | | | | | | | | | | | Provision for depreciation | | | 11 | | | 10 | | | 23 | | | 20 | | | Amortization of regulatory assets | | | 25 | | | 23 | | | 54 | | | 48 | | | Deferred costs recoverable as regulatory assets | | | (14 | ) | | (13 | ) | | (30 | ) | | (30 | ) | | Deferred income taxes and investment tax credits, net | | | (2 | ) | | (8 | ) | | (2 | ) | | (5 | ) | | Other non-cash charges | | | - | | | - | | | (4 | ) | | - | | | Cash earnings (Non-GAAP) | | $ | 36 | | $ | 19 | | $ | 73 | | $ | 58 | | | | | | | | | | | | | | | | |
The $17$1 million and $15 million increasesincrease in cash earnings for the second quarter and first six months of 2005, respectively, areis described above under "Results“Results of Operations".Operations.” The $20$31 million working capital change primarily resulted from a $72 million decrease in cash provided from the settlement of receivables, a $7 million decrease in accrued taxes, a $3 million decrease in prepayments, a $2 million increase in working capitalcash collateral returned to suppliers, and a $4 million decrease in the second quarter of 2005 primarily resulted from changes of $14 million in accounts receivable, $11 million in accounts payable, and $9 million inother accrued taxes,liabilities, partially offset by a change of $7$57 million in accrued interest. The $24 million increase in working capitaldecreased outflows for the first six months of 2005 primarily resulted from changes of $78 million in accounts receivable, partially offset by changes of $45 million in accounts payable and $4 million in accrued interest.payable.
Cash Flows From Financing Activities
For the second quarter of 2005, netNet cash used for financing activities was $70$2 million compared to $120 million in the second quarter of 2004. The $50 million decrease resulted primarily from a reduction in debt redemptions -- $37 million in the second quarter of 2005 compared to $100 million in the second quarter of 2004 - partially offset by an $8 million increase in repayments on short-term borrowings and a $5 million increase in common stock dividends to FirstEnergy. For the first six months of 2005, net cash used for financing activities was2006 compared to $51 million compared to $7 million of net cash provided from financing activities in the same period of 2004.2005. The $58decrease primarily reflects a $38 million changedecrease in the six month period reflected new financings of $21long-term debt redemptions and a $34 million (net short-term borrowings)decrease in common stock dividend payments to FirstEnergy in the first six months of 2005 compared to $247 million (long-term debt) in the same period of 2004. This change was2006, partially offset by $38a $23 million of debt redemptionsdecrease in the first six months of 2005 compared to $216 million of debt redemptions in the first six months of 2004. In addition, common stock dividends to FirstEnergy increased by $9 million in the first six months of 2005.short-term borrowings.
As of June 30, 2005,2006, Met-Ed had approximately $15$32 million of cash and temporary investments (including(which included short-term notes receivable from associated companies) and $101$139 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 PUCHA, to incur short-term debt up to $250 million (includingand authorization from the utilityPPUC to incur money pool). Under the termspool borrowings up to $300 million. In addition, Met-Ed has $80 million of Met-Ed’s senior note indenture, no more first mortgage bonds can be issuedavailable accounts receivable financing facilities as long as the senior bonds are outstanding. Met-Ed had no restrictions on the issuance of preferred stock.
June 30, 2006 through Met-Ed Funding LLC, (Met-Ed Funding), aMet-Ed’s wholly owned subsidiary of Met-Ed, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Met-Ed. Met-Ed Funding can borrow up to $80 million under a receivables financing arrangement.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 June 30, 2005,2006 the facility was drawn for $67$66 million. On July 15, 2005,In June 2006, the facility was renewed until June 29, 2006.28, 2007. The annual facility fee is 0.25%0.125% on the entire finance limit.
Under the terms of Met-Ed’s senior note indenture, FMBs may no longer be issued so long as the senior notes are outstanding. As of June 30, 2006, Met-Ed had the capability to issue $633 million of additional senior notes based upon FMB collateral. Met-Ed had no restrictions on the issuance of preferred stock.
Met-Ed, FirstEnergy, OE, Penn, CEI, TE, JCP&L, 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 expiration date, as the same may be extended. Met-Ed’s borrowing limit under the facility is $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 the existing credit facilities and accounts receivable financing facilities totaled $264 million as of June 30, 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 June 30, 2006, Met-Ed’s debt to total capitalization as defined under the revolving credit facility was 38%.
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 second quarterfirst six months of 20052006 was 2.93%4.86%.
On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as borrowers, entered into a syndicated $2 billion five-year revolving credit facility. 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 termination date, as the same may be extended. Met-Ed’s borrowing limit under the facility is $250 million.
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 June 30, 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 positive.
On May 16, 2005, S&P affirmed its 'BBB-' corporate credit ratings on FirstEnergy Corp. and its units and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmation and outlook revision reflects the successful restart of the three nuclear units from their respective outages that occurred during the first half of 2005. S&P noted that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projected and as the nuclear operations further stabilize.
On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s rating outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in its outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.
On May 1, 2005, Met-Ed redeemed all of its outstanding shares of 6.00% Series Pollution Control Revenue Bonds at par, plus accrued interest to the date of redemption.
Cash Flows From Investing Activities
In the second quarterfirst six months of 2005, net2006, Met-Ed’s cash used for investing activities totaled $16$57 million, compared to $71 million of net cash provided from investing activities in the second quarter of 2004. The change in the second quarter resulted from an $79 million decrease in loan repayments from associated companies and a $6 million increase in property additions. In the first six months of 2005, net cash used for investing activities totaledwith $38 million, compared to $57 million in the first six monthssame period of 2004.2005. The decrease in the first six months of 2005increase primarily resulted from a $34 million increase in loan repayments from associated companies, partially offset by a $13 million increase in property additions.additions and a $7 million increase in loans to associated companies. Expenditures for property additions primarily support Met-Ed’s energy delivery operations.operations and reliability initiatives.
Met-Ed's capital spending for the period 2005 through 2007 is expected to be about $205 million for property additions, of which approximately $66 million applies to 2005. During the remaining two quarterslast half of 2005,2006, capital requirements for property additions are expected to be about $32$29 million. Met-Ed has additional requirements of approximately $100 million for maturing long-term debt during the remainder of 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 has no additional requirements
Met-Ed's capital spending for maturing long-term debt during the remainderperiod 2006 through 2010 is expected to be about $360 million, of 2005.which approximately $76 million applies to 2006. The capital spending is primarily for property additions supporting the distribution of electricity.
Market Risk Information
Met-Ed uses various market-risk-sensitivemarket 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 resulting from fluctuatingdue 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 June 30, 2005, Met-Ed’s1978. 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. On April 1, 2006, Met-Ed elected to apply the normal purchase and normal sale exception to certain NUG power purchase agreements with an above-market fair value of $1 million (included in “Other” in the table below) in accordance with guidance in DIG C20. The change in the fair value of commodity derivative contracts related to energy production during the second quarter and first six months of 2006 is summarized in the following table:
| | | Three Months Ended | | Six Months Ended | | Increase (Decrease) in the Fair Value | | June 30, 2006 | | June 30, 2006 | | of Commodity Derivative Contracts | | Non-Hedge | | Hedge | | Total | | Non-Hedge | | Hedge | | Total | | | | | (In millions) | | Change in the Fair Value of | | | | | | | | | | | | | | Commodity Derivative Contracts: | | | | | | | | | | | | | | | Outstanding net asset at beginning of period | | $ | 24 | | $ | - | | $ | 24 | | $ | 27 | | $ | - | | $ | 27 | | | New contract value when entered | | | - | | | - | | | - | | | - | | | - | | | - | | | Additions/change in value of existing contracts | | | - | | | - | | | - | | | 4 | | | - | | | 4 | | | Change in techniques/assumptions | | | - | | | - | | | - | | | - | | | - | | | - | | | Settled contracts | | | (2 | ) | | - | | | (2 | ) | | (9 | ) | | - | | | (9 | ) | | Other | | | 1 | | | - | | | 1 | | | 1 | | | - | | | 1 | | Net Assets - Derivative Contracts at End of Period (1) | | $ | 23 | | $ | - | | $ | 23 | | $ | 23 | | $ | - | | $ | 23 | | | | | | | | | | | | | | | | | | | | | | | Impact of Changes in Commodity Derivative Contracts(2) | | | | | | | | | | | | | | | | | | | | | Income Statement effects (pre-tax) | | $ | (2 | ) | $ | - | | $ | (2 | ) | $ | (2 | ) | $ | - | | $ | (2 | ) | | Balance Sheet effects: | | | | | | | | | | | | | | | | | | | | | OCI (pre-tax) | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | | Regulatory liability | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | | | | | | | | | | | | | | | | | | | | | |
(1)Includes $23 million in non-hedge commodity derivative contract, was an embedded option withwhich is offset by a fairregulatory liability. (2)Represents the change in value of $27 million. A decrease of $5 millionexisting contracts, settled contracts and changes in the value of this asset was recorded as a decrease in regulatory liabilities, and therefore, had no impact on net income.techniques/assumptions.
Derivatives are included on the Consolidated Balance Sheet as of June 30, 2006 as follows:
Balance Sheet Classification | | | Non-Hedge | | | Hedge | | | Total | | | | | (In millions) | Non-Current- | | | | | | | | | | | Other deferred charges | | $ | 23 | | $ | - | | $ | 23 | | Other noncurrent liabilities | | | - | | | - | | | - | | | | | | | | | | | | | Net assets | | $ | 23 | | $ | - | | $ | 23 | | | | | | | | | | | |
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of June 30, 20052006 are summarized by year in the following table:
Sources of Information - | | | | | | | | | | | | | | | | | | Fair Value by Contract Year | | | | 2005(1) | | 2006 | | 2007 | | 2008 | | 2009 | | Thereafter | | Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Prices based on external sources(2) | | | | | $ | 5 | | $ | 6 | | $ | 6 | | $ | - | | $ | - | | $ | - | | $ | 17 | | | Prices based on models | | | | | | - | | | - | | | - | | | 4 | | | 3 | | | 3 | | | 10 | | | Total | | | | | $ | 5 | | $ | 6 | | $ | 6 | | $ | 4 | | $ | 3 | | $ | 3 | | $ | 27 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) For the last two quarters of 2005. (2) Broker quote sheets. | | | | | | | | | | | | | | | | | | | | | | | | | |
Source of Information | | | | | | | | | | | | | | | | Fair Value by Contract Year | | 2006(1) | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter | | Total | | | | (In millions) | Other external sources (2) | | $ | 5 | | $ | 5 | | $ | 5 | | $ | - | | $ | - | | $ | - | | $ | 15 | Prices based on models(3) | | | - | | | - | | | - | | | 4 | | | 4 | | | - | | | 8 | | | | | | | | | | | | | | | | | | | | | | | | Total(3) | | $ | 5 | | $ | 5 | | $ | 5 | | $ | 4 | | $ | 4 | | $ | - | | $ | 23 |
(1)For the last two quarters of 2006. (2)Broker quote sheets. (3)Includes $23 million from a non-hedge commodity derivative contract 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 (an increase or decrease depending on the derivative position) 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 June 30, 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 $134$146 million and $142 million as of June 30, 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 June 30, 2005.2006.
Regulatory Matters Regulatory assets are costs which have been authorized by 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. 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 June 30, 20052006 and December 31, 20042005 were $673$359 million and $693$310 million, respectively.
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 PPUC directives,the PPUC’s direction, Met-Ed and Penelec have been negotiating with interested partiesfiled supplements to their tariffs that became effective in an attemptOctober 2003 and that reflected the CTC rates and shopping credits in effect prior to resolve the merger savings issues that are the subject of remand from the Commonwealth Court.June 2001 order. Met-Ed’s and Penelec’s combined portion of total net merger savings during 2001 - 2004 is estimated to be approximately $31.5$51 million. A procedural schedule was established by the ALJ on January 17, 2006 and the companies filed initial testimony on March 1, 2006. On May 4, 2006, the PPUC consolidated this proceeding with the April 13, 2005,10, 2006 comprehensive rate filing proceeding discussed below. Met-Ed and Penelec are unable to predict the outcome of this matter.
In an October 16, 2003 order, the PPUC approved September 30, 2004 as the date for Met-Ed's NUG trust fund refunds. The PPUC order also denied its accounting treatment request regarding the CTC rate/shopping credit swap by requiring Met-Ed to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed filed an Objection with the Commonwealth Court asking that the Court reverse this PPUC finding; a Commonwealth Court judge subsequently denied its Objection on October 27, 2003 without explanation. On October 31, 2003, Met-Ed 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 Objection was intended to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed on January 28, 2005. Oral arguments were held on June 8, 2006. On July 19, 2006, the Commonwealth Court issued its decision affirming the PPUC’s prior orders. Although the decision denied the appeal of Met-Ed, it had previously accounted for the treatment of costs required by the PPUC’s October 2003 orders. As of June 30, 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 were $335 million and $57 million, respectively. Penelec's $57 million is subject to the pending resolution of taxable income issues associated with NUG trust fund proceeds. The PPUC is reviewing a January 2006 change in Met-Ed’s and Penelec’s NUG purchase power stranded cost accounting methodology. If the PPUC orders Met-Ed and Penelec to reverse the change in accounting methodology, this would result in a pre-tax loss of $10.3 million for Met-Ed. On November 18, 2004, the FERC issued an interim order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism 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 remand proceeding thatFERC hearings concerning the parties should report the statuscalculation and imposition of the negotiations to the PPUC with a copy to the ALJ.SECA charges. The parties exchanged settlement proposalshearing was held in May 2006. Initial briefs were submitted on June 9, 2006, and reply briefs were filed on June 2005 and continue27, 2006. The FERC has ordered the Presiding Judge to have settlement discussions.issue an initial decision by August 11, 2006.
Met-Ed purchases a portion of its PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless either party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed is authorized to defer differences between NUG contract costs and current market prices.
On January 12, 2005, Met-Ed filed a request with the PPUC for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $4 million per month.
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 referralrefund 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. Hearings in the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate. The ALJ recommended an April 1, 2006 effective date for this change in rate design. If the FERC accepts this recommendation, the transmission rate applicable to many load zones in PJM would increase. FirstEnergy believes that significant additional transmission revenues would have to be recovered from the JCP&L, Met-Ed and Penelec transmission zones within PJM. The Companies, as part of the Responsible Pricing Alliance, intend to submit a brief on exceptions within thirty days of the initial decision. Following submission of reply exceptions, the case is expected to be reviewed by the FERC with a decision anticipated in the fourth quarter of 2006.
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 all intervened in the case. 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 has deferred approximately $46 million, representing transmission costs that were incurred from January 1, 2006 through June 30, 2006. On June 5, 2006, the OCA filed before the Commonwealth Court a petition for review of the PPUC’s approval of the deferral. On July 12, 2006, the Commonwealth Court granted the PPUC’s motion to quash the OCA’s appeal. The ratemaking treatment of the deferral will be determined in the comprehensive rate filing proceeding discussed further below. Met-Ed purchases a portion of its 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 under its contracts with NUGs and other unaffiliated suppliers. The FES arrangement reduces Met-Ed's exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. 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 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 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 its PLR obligations for which Committed Resources (i.e., non-utility generation under contract to Met-Ed, Met-Ed-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 an agent for Met-Ed in procuring the services under 1.(b) above; and
3. The pricing provision of the wholesale power sales agreement shall remain unchanged provided Met-Ed complies 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 procures 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 its 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 to satisfy the portion of its 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 purchased power costs could materially increase. If Met-Ed was to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase its generation prices to customers, Met-Ed would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, Met-Ed'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 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 preferred approach involving accounting deferrals is approved, the filing would increase annual revenues by $216 million. That filing includes, among other things, a request to charge customers for an increasing amount of market priced power procured through a CBP 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 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 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 of $37 million annually. The PPUC suspended the effective date (June 10, 2006) of these rate changes for seven months after the filing as permitted under Pennsylvania law. If the PPUC adopts the overall positions taken in the intervenors’ testimony as filed, this would have a material adverse effect on the financial statements of FirstEnergy, Met-Ed and Penelec. Hearings are scheduled for late August 2006 and a PPUC decision is expected early in the first quarter of 2007.
See Note 1411 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 Met-Ed.
Environmental Matters
Met-Ed accrues environmental liabilities 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 June 30, 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 $47,000 as of June 30, 2005. FirstEnergy plans See Note 10(B) to issuethe consolidated financial statements for further details and a report that will disclose the Companies’complete discussion of 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.matters.
Other Legal Proceedings
Power Outages and Related Litigation 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, 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 websiteWeb site (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. FirstEnergy is also is proceeding with the implementation of the 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 new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, thatequipment. The 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 FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements
In addition to the trainingabove proceedings, FirstEnergy was named in a complaint filed in Michigan State Court by an individual who is not a customer of control room operators, before determiningany FirstEnergy company. FirstEnergy's motion to dismiss the next steps, if any,matter was denied on June 2, 2006. FirstEnergy has since filed an appeal, which is pending. A responsive pleading to this matter has been filed. Also, the complaint has been amended to include an additional party. No estimate of potential liability has been undertaken in the proceeding.this matter. 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.
New Accounting Standards and Interpretations
FSP FIN 46(R)-6 - “Determining the Variability to Be Considered in Applying FASB interpretation No. 46(R)”
In April 2006, the FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should determine the variability to be considered in applying FASB interpretation No. 46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the first quarter of 2004, consolidating VIE’s when FirstEnergy or one of its subsidiaries is determined to be the VIE’s primary beneficiary. The variability that is considered in applying interpretation 46(R) affects the determination of (a) whether the entity is a VIE; (b) which interests are variable interests in the entity; and (c) which party, if any, is the primary beneficiary of the VIE. This FSP states that the variability to be considered shall be based on an analysis of the design of the entity, involving two steps: | Step 1: | SFAS 154 - "Accounting ChangesAnalyze the nature of the risks in the entity
| | Step 2: | Determine the purpose(s) for which the entity was created and Error Corrections - a replacement of APB Opinion No. 20determine the variability the entity is designed to create and FASB Statement No. 3"pass along to its interest holders. |
In May 2005,After determining the FASB issued SFAS 154variability to changeconsider, the requirements for accounting and reporting a changeenterprise can determine which interests are designed to absorb that variability. The guidance in accounting principle. It appliesthis FSP is applied prospectively to all voluntary changes in accounting principleentities (including newly created entities) with which that enterprise first becomes involved and to changesall entities previously required by an accounting pronouncementto be analyzed under interpretation 46(R) when that pronouncementa reconsideration event has occurred after July 1, 2006. Met-Ed does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances,expect this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and thathave a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement ofmaterial impact on its financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Met-Ed will adopt this Statement effective January 1, 2006.statements.
FIN 47, "Accounting48 - “Accounting for Conditional Asset Retirement ObligationsUncertainty in Income Taxes - an interpretation of FASB Statement No. 143"109.”
On March 30, 2005,In June 2006, the FASB issued FIN 4748 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to clarify the scopebe taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and timingtransition. The evaluation of liability recognition for conditional asset retirement obligations. Undera tax position in accordance with this interpretation companies are requiredwill be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit 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.financial statements. This Interpretationinterpretation is effective no later than the end offor fiscal years endingbeginning after December 15, 2005. Therefore, Met-Ed will adopt this Interpretation in the fourth quarter of 2005.2006. Met-Ed is currently evaluating the effectimpact of this Interpretation will have on its financial statements.Statement.
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 indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, Met-Ed continues to evaluate its investments as required by existing authoritative guidance.
PENNSYLVANIA ELECTRIC COMPANY | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In thousands) | | | | | | | | | | | | | OPERATING REVENUES | | $ | 262,097 | | $ | 242,202 | | $ | 556,026 | | $ | 498,647 | | | | | | | | | | | | | | | | | OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | Purchased power | | | 139,292 | | | 139,452 | | | 289,549 | | | 295,828 | | | Other operating costs | | | 62,794 | | | 45,980 | | | 116,607 | | | 85,888 | | | Provision for depreciation | | | 12,479 | | | 11,510 | | | 24,985 | | | 22,948 | | | Amortization of regulatory assets | | | 13,118 | | | 13,720 | | | 26,303 | | | 27,371 | | | General taxes | | | 16,134 | | | 16,920 | | | 34,340 | | | 33,882 | | | Income taxes | | | 2,300 | | | 1,744 | | | 18,092 | | | 4,307 | | | Total operating expenses and taxes | | | 246,117 | | | 229,326 | | | 509,876 | | | 470,224 | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 15,980 | | | 12,876 | | | 46,150 | | | 28,423 | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE) (net of income taxes) | | | (316 | ) | | 447 | | | 420 | | | 363 | | | | | | | | | | | | | | | | | NET INTEREST CHARGES: | | | | | | | | | | | | | | | Interest on long-term debt | | | 7,423 | | | 7,568 | | | 14,882 | | | 15,015 | | | Allowance for borrowed funds used during construction | | | (264 | ) | | (62 | ) | | (389 | ) | | (132 | ) | | Deferred interest | | | - | | | - | | | - | | | 190 | | | Other interest expense | | | 2,668 | | | 2,768 | | | 4,856 | | | 5,005 | | | Net interest charges | | | 9,827 | | | 10,274 | | | 19,349 | | | 20,078 | | | | | | | | | | | | | | | | | NET INCOME | | | 5,837 | | | 3,049 | | | 27,221 | | | 8,708 | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | Unrealized gain (loss) on derivative hedges | | | 16 | | | (635 | ) | | 32 | | | (635 | ) | | Unrealized loss on available for sale securities | | | (18 | ) | | (18 | ) | | (21 | ) | | (10 | ) | | Other comprehensive income (loss) | | | (2 | ) | | (653 | ) | | 11 | | | (645 | ) | | Income tax benefit related to other comprehensive income | | | 6 | | | 5 | | | - | | | 2 | | | Other comprehensive income (loss), net of tax | | | 4 | | | (648 | ) | | 11 | | | (643 | ) | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 5,841 | | $ | 2,401 | | $ | 27,232 | | $ | 8,065 | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of | | | these statements. | | | | | | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | (Unaudited) | | | | | | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2006 | | 2005 | | 2006 | | 2005 | | | | | | | | | | | | | | | | (In thousands) | | | | | | | | | | | | | REVENUES | | $ | 264,999 | | $ | 262,097 | | $ | 556,751 | | $ | 556,026 | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | Purchased power | | | 146,875 | | | 139,292 | | | 308,516 | | | 289,549 | | | Other operating costs | | | 48,133 | | | 62,794 | | | 86,475 | | | 116,607 | | | Provision for depreciation | | | 11,798 | | | 12,479 | | | 24,441 | | | 24,985 | | | Amortization of regulatory assets | | | 12,979 | | | 13,118 | | | 27,794 | | | 26,303 | | | Deferral of new regulatory assets | | | (11,815 | ) | | - | | | (11,815 | ) | | - | | | General taxes | | | 17,458 | | | 16,134 | | | 36,847 | | | 34,340 | | | Total expenses | | | 225,428 | | | 243,817 | | | 472,258 | | | 491,784 | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 39,571 | | | 18,280 | | | 84,493 | | | 64,242 | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | Miscellaneous income | | | 1,627 | | | 938 | | | 3,997 | | | 1,268 | | | Interest expense | | | (11,599 | ) | | (10,091 | ) | | (22,135 | ) | | (19,738 | ) | | Capitalized interest | | | 422 | | | 264 | | | 769 | | | 389 | | | Total other income (expense) | | | (9,550 | ) | | (8,889 | ) | | (17,369 | ) | | (18,081 | ) | | | | | | | | | | | | | | | | INCOME TAXES | | | 14,564 | | | 3,554 | | | 28,518 | | | 18,940 | | | | | | | | | | | | | | | | | NET INCOME | | | 15,457 | | | 5,837 | | | 38,606 | | | 27,221 | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME: | | | | | | | | | | | | | | | Unrealized gain on derivative hedges | | | 16 | | | 16 | | | 32 | | | 32 | | | Unrealized loss on available for sale securities | | | (14 | ) | | (18 | ) | | (18 | ) | | (21 | ) | | Other comprehensive income (loss) | | | 2 | | | (2 | ) | | 14 | | | 11 | | | Income tax expense (benefit) related to other | | | | | | | | | | | | | | | comprehensive income | | | 1 | | | (6 | ) | | 7 | | | - | | | Other comprehensive income, net of tax | | | 1 | | | 4 | | | 7 | | | 11 | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 15,458 | | $ | 5,841 | | $ | 38,613 | | $ | 27,232 | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements. |
PENNSYLVANIA ELECTRIC COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | | June 30, | | December 31, | | | | | 2005 | | 2004 | | | | | (In thousands) | | ASSETS | | | | | | UTILITY PLANT: | | | | | | | In service | | $ | 1,979,489 | | $ | 1,981,846 | | | Less - Accumulated provision for depreciation | | | 763,857 | | | 776,904 | | | | | | 1,215,632 | | | 1,204,942 | | | Construction work in progress | | | 23,471 | | | 22,816 | | | | | | 1,239,103 | | | 1,227,758 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 109,484 | | | 109,620 | | | Non-utility generation trusts | | | 96,968 | | | 95,991 | | | Long-term notes receivable from associated companies | | | 14,342 | | | 14,001 | | | Other | | | 14,719 | | | 18,746 | | | | | | 235,513 | | | 238,358 | | CURRENT ASSETS: | | | | | | | | | Cash and cash equivalents | | | 35 | | | 36 | | | Notes receivable from associated companies | | | - | | | 7,352 | | | Receivables - | | | | | | | | | Customers (less accumulated provisions of $4,102,000 and $4,712,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 119,927 | | | 121,112 | | | Associated companies | | | 23,671 | | | 97,528 | | | Other | | | 8,218 | | | 12,778 | | | Prepayments and other | | | 29,305 | | | 7,198 | | | | | | 181,156 | | | 246,004 | | DEFERRED CHARGES: | | | | | | | | | Goodwill | | | 886,559 | | | 888,011 | | | Regulatory assets | | | 183,075 | | | 200,173 | | | Other | | | 12,486 | | | 13,448 | | | | | | 1,082,120 | | | 1,101,632 | | | | | $ | 2,737,892 | | $ | 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 | | | 1,206,351 | | | 1,205,948 | | | Accumulated other comprehensive loss | | | (52,802 | ) | | (52,813 | ) | | Retained earnings | | | 43,289 | | | 46,068 | | | Total common stockholder's equity | | | 1,302,650 | | | 1,305,015 | | | Long-term debt and other long-term obligations | | | 478,807 | | | 481,871 | | | | | | 1,781,457 | | | 1,786,886 | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | | 8,017 | | | 8,248 | | | Short-term borrowings - | | | | | | | | | Associated companies | | | 65,888 | | | 241,496 | | | Other | | | 139,000 | | | - | | | Accounts payable - | | | | | | | | | Associated companies | | | 29,825 | | | 56,154 | | | Other | | | 31,956 | | | 25,960 | | | Accrued taxes | | | 18,727 | | | 7,999 | | | Accrued interest | | | 9,661 | | | 9,695 | | | Other | | | 18,384 | | | 23,750 | | | | | | 321,458 | | | 373,302 | | NONCURRENT LIABILITIES: | | | | | | | | | Power purchase contract loss liability | | | 336,696 | | | 382,548 | | | Asset retirement obligation | | | 68,537 | | | 66,443 | | | Accumulated deferred income taxes | | | 58,327 | | | 37,318 | | | Retirement benefits | | | 120,151 | | | 118,247 | | | Other | | | 51,266 | | | 49,008 | | | | | | 634,977 | | | 653,564 | | COMMITMENTS AND CONTINGENCIES (Note 13) | | | | | | | | | | | $ | 2,737,892 | | $ | 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) | | | | | June 30, | | December 31, | | | | | 2006 | | 2005 | | | | | (In thousands) | | ASSETS | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 49 | | $ | 35 | | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $4,044,000 and $4,184,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 119,103 | | | 129,960 | | | Associated companies | | | 2,173 | | | 18,626 | | | Other | | | 9,625 | | | 12,800 | | | Notes receivable from associated companies | | | 21,090 | | | 17,624 | | | Prepaid gross receipts taxes | | | 22,626 | | | - | | | Prepayments and other | | | 3,874 | | | 7,936 | | | | | | 178,540 | | | 186,981 | | UTILITY PLANT: | | | | | | | | | In service | | | 2,095,438 | | | 2,043,885 | | | Less - Accumulated provision for depreciation | | | 793,523 | | | 784,494 | | | | | | 1,301,915 | | | 1,259,391 | | | Construction work in progress | | | 27,761 | | | 30,888 | | | | | | 1,329,676 | | | 1,290,279 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 115,252 | | | 113,368 | | | Non-utility generation trusts | | | 97,866 | | | 96,761 | | | Other | | | 531 | | | 918 | | | | | | 213,649 | | | 211,047 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 877,651 | | | 882,344 | | | Prepaid pension costs | | | 92,307 | | | 89,637 | | | Other | | | 37,150 | | | 38,289 | | | | | | 1,007,108 | | | 1,010,270 | | | | | $ | 2,728,973 | | $ | 2,698,577 | | LIABILITIES AND CAPITALIZATION | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Short-term borrowings- | | | | | | | | | Associated companies | | $ | 220,801 | | $ | 261,159 | | | Other | | | 67,000 | | | - | | | Accounts payable- | | | | | | | | | Associated companies | | | 16,256 | | | 33,770 | | | Other | | | 46,783 | | | 38,277 | | | Accrued taxes | | | 17,148 | | | 27,905 | | | Accrued interest | | | 9,094 | | | 8,905 | | | Other | | | 17,796 | | | 19,756 | | | | | | 394,878 | | | 389,772 | | 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 | | | 1,197,889 | | | 1,202,551 | | | Accumulated other comprehensive loss | | | (302 | ) | | (309 | ) | | Retained earnings | | | 64,429 | | | 25,823 | | | Total common stockholder's equity | | | 1,367,828 | | | 1,333,877 | | | Long-term debt and other long-term obligations | | | 476,904 | | | 476,504 | | | | | | 1,844,732 | | | 1,810,381 | | NONCURRENT LIABILITIES: | | | | | | | | | Regulatory liabilities | | | 135,494 | | | 162,937 | | | Accumulated deferred income taxes | | | 119,912 | | | 106,871 | | | Retirement benefits | | | 105,980 | | | 102,046 | | | Asset retirement obligation | | | 74,574 | | | 72,295 | | | Other | | | 53,403 | | | 54,275 | | | | | | 489,363 | | | 498,424 | | COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | | | | $ | 2,728,973 | | $ | 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 | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | Six Months Ended | | | | | June 30, | | | | | 2006 | | 2005 | | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 38,606 | | $ | 27,221 | | | Adjustments to reconcile net income to net cash from operating activities - | | | | | | | | | Provision for depreciation | | | 24,441 | | | 24,985 | | | Amortization of regulatory assets | | | 27,794 | | | 26,303 | | | Deferral of new regulatory assets | | | (11,815 | ) | | - | | | Deferred costs recoverable as regulatory assets | | | (54,092 | ) | | (35,946 | ) | | Deferred income taxes and investment tax credits, net | | | 13,206 | | | 2,647 | | | Accrued retirement benefit obligations | | | 1,264 | | | 1,905 | | | Accrued compensation, net | | | (371 | ) | | (2,386 | ) | | Decrease (increase) in operating assets - | | | | | | | | | Receivables | | | 30,485 | | | 79,602 | | | Prepayments and other current assets | | | (18,565 | ) | | (22,107 | ) | | Increase (decrease) in operating liabilities - | | | | | | | | | Accounts payable | | | (9,008 | ) | | (20,333 | ) | | Accrued taxes | | | (10,756 | ) | | 10,728 | | | Accrued interest | | | 190 | | | (34 | ) | | Other | | | 8,817 | | | 4,365 | | | Net cash provided from operating activities | | | 40,196 | | | 96,950 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing - | | | | | | | | | Short-term borrowings, net | | | 26,642 | | | - | | | Redemptions and Repayments - | | | | | | | | | Long-term debt | | | - | | | (3,521 | ) | | Short-term borrowings, net | | | - | | | (36,608 | ) | | Dividend Payments - | | | | | | | | | Common stock | | | - | | | (30,000 | ) | | Net cash provided from (used for) financing activities | | | 26,642 | | | (70,129 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (60,747 | ) | | (33,683 | ) | | Loan repayments from (loans to) associated companies, net | | | (3,466 | ) | | 7,011 | | | Proceeds from nuclear decommissioning trust fund sales | | | 51,536 | | | 24,127 | | | Investments in nuclear decommissioning trust funds | | | (51,536 | ) | | (24,127 | ) | | Other, net | | | (2,611 | ) | | (150 | ) | | Net cash used for investing activities | | | (66,824 | ) | | (26,822 | ) | | | | | | | | | | | Net increase (decrease) in cash and cash equivalents | | | 14 | | | (1 | ) | | Cash and cash equivalents at beginning of period | | | 35 | | | 36 | | | Cash and cash equivalents at end of period | | $ | 49 | | $ | 35 | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements. |
PENNSYLVANIA ELECTRIC COMPANY | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | Three Months Ended | | Six Months Ended | | | | | June 30, | | June 30, | | | | | 2005 | | 2004 | | 2005 | | 2004 | | | | | (In thousands) | | | | | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | Net income | | $ | 5,837 | | $ | 3,049 | | $ | 27,221 | | $ | 8,708 | | | Adjustments to reconcile net income to net cash from | | | | | | | | | | | | | | | operating activities - | | | | | | | | | | | | | | | Provision for depreciation | | | 12,479 | | | 11,510 | | | 24,985 | | | 22,948 | | | Amortization of regulatory assets | | | 13,118 | | | 13,720 | | | 26,303 | | | 27,371 | | | Deferred costs recoverable as regulatory assets | | | (16,513 | ) | | (18,511 | ) | | (35,946 | ) | | (36,504 | ) | | Deferred income taxes and investment tax credits, net | | | 201 | | | (23,508 | ) | | 2,647 | | | 1,734 | | | Accrued retirement benefit obligations | | | 1,037 | | | 839 | | | 1,905 | | | 3,641 | | | Accrued compensation, net | | | 244 | | | (878 | ) | | (2,386 | ) | | 1,377 | | | Decrease (increase) in operating assets - | | | | | | | | | | | | | | | Receivables | | | 40,457 | | | 65,624 | | | 79,602 | | | 53,495 | | | Prepayments and other current assets | | | 13,012 | | | 12,104 | | | (22,107 | ) | | (34,950 | ) | | Increase (decrease) in operating liabilities - | | | | | | | | | | | | | | | Accounts payable | | | 3,901 | | | (4,022 | ) | | (20,333 | ) | | (14,760 | ) | | Accrued taxes | | | 523 | | | (1,091 | ) | | 10,728 | | | (7,574 | ) | | Accrued interest | | | (5,615 | ) | | (5,385 | ) | | (34 | ) | | (2,749 | ) | | Other | | | 4,582 | | | 20,635 | | | 4,365 | | | 24,289 | | | Net cash provided from operating activities | | | 73,263 | | | 74,086 | | | 96,950 | | | 47,026 | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | New Financing - | | | | | | | | | | | | | | | Long-term debt | | | - | | | - | | | - | | | 150,000 | | | Short-term borrowings, net | | | - | | | 68,962 | | | - | | | 7,636 | | | Redemptions and Repayments - | | | | | | | | | | | | | | | Long-term debt | | | (3,508 | ) | | (125,108 | ) | | (3,521 | ) | | (125,212 | ) | | Short-term borrowings, net | | | (34,805 | ) | | - | | | (36,608 | ) | | - | | | Dividend Payments - | | | | | | | | | | | | | | | Common stock | | | (25,000 | ) | | (5,000 | ) | | (30,000 | ) | | (5,000 | ) | | Net cash provided from (used for) financing activities | | | (63,313 | ) | | (61,146 | ) | | (70,129 | ) | | 27,424 | | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | Property additions | | | (18,290 | ) | | (12,042 | ) | | (33,683 | ) | | (23,236 | ) | | Non-utility generation trust contribution | | | - | | | - | | | - | | | (50,614 | ) | | Loan repayments from (loans to) associated companies, net | | | 10,093 | | | 51 | | | 7,011 | | | (20 | ) | | Other, net | | | (1,753 | ) | | (949 | ) | | (150 | ) | | (580 | ) | | Net cash used for investing activities | | | (9,950 | ) | | (12,940 | ) | | (26,822 | ) | | (74,450 | ) | | | | | | | | | | | | | | | | | Net change in cash and cash equivalents | | | - | | | - | | | (1 | ) | | - | | | Cash and cash equivalents at beginning of period | | | 35 | | | 36 | | | 36 | | | 36 | | | Cash and cash equivalents at end of period | | $ | 35 | | $ | 36 | | $ | 35 | | $ | 36 | | | | | | | | | | | | | | | | | | The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an 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 June 30, 2005,2006, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2006 and 2005 and 2004.the consolidated statement of cash flows for the six-month period ended June 30, 2006 and 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 have 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[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 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 6 tostatements] dated February 27, 2006, we expressed an unqualified opinion on those consolidated financial statements) dated March 7, 2005, 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.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 July 29, 2005August 4, 2006
PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S DISCUSSION ANDANALYSIS OF RESULTS OF OPERATIONSAND 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 second quarter of 20052006 increased to $15 million, compared to $6 million in the second quarter of 2005. In the first six months of 2006, net income increased to $39 million, compared to $27 million in the first six months of 2005. The increase in net income for both periods resulted from lower other operating costs, deferral of new regulatory assets, and higher revenues which were partially offset by higher purchased power costs, general taxes and interest expense, as discussed below.
Revenues
Revenues increased by $3 million in the second quarter of 2004. The increase resulted from higher operating revenues that were partially offset by higher operating costs - primarily transmission expenses. During the first six months of 2005, net income increased to $27 million compared to $92006 and $1 million in the first six months of 2004. The increase resulted from2006, compared to the same periods of 2005. Increases in both periods were due primarily to higher operatingretail generation revenues and lower purchased power costs, partially offset by higher operating costslower transmission and income taxes.
Operatingdistribution revenues. Retail generation revenues increased by $20$12 million in the second quarter of 2005 compared to the second quarter of 2004, primarily due to higher transmission revenues. Transmission revenues increased $202006 and $23 million as a result of a change in the power supply agreement with FES in the second quarter of 2004. The change also resulted in higher transmission expenses as discussed further below.
Operating revenues increased by $57 million infor the first six months of 2005 compared2006 primarily due to higher KWH sales to industrial customers and higher composite unit prices in all customer classes. Industrial sales increased $8 million for the second quarter of 2006 and $15 million for the first six months of 2004,2006 primarily due to higher transmission, retail generation and distribution revenues. Transmission revenues increased $43 million as a resultthe return of the power supply agreement change with FES.
Total retail sales increased $11 million duecustomers to higher retail generation revenues of $9 million and distribution revenues of $2 million, respectively. Retail generation revenues increased, principallyPenelec from increased generation KWH sales to all customer sectors (residential - $2 million; industrial - $4 million and commercial - $3 million) reflecting increases in KWH sales of 1.9%, 3.7% and 2.7%, respectively, combined with higher unit costs. Industrial KWH sales increased despite a small increase in customer shopping. Salesalternative suppliers. Generation service provided by alternative suppliers as a percent of total industrial sales delivered in Penelec’s franchiseservice area increaseddecreased by 0.7%, while residential12.1 percentage points and commercial customer shopping remained constant13.2 percentage points in the second quarter and the first six months of 2005 compared to2006, respectively. The higher composite unit prices also increased generation revenues from residential customers by $1 million and $3 million and from commercial customers by $3 million and $5 million in the same periodsecond quarter and first six months of 2004.2006, respectively.
Distribution revenues increaseddecreased by $2$1 million in the second quarter of 2006 and by $3 million in the first six months of 20052006, compared with the same periods of 2005. The decreases were primarily due to 1.1% and 1.9% decreases in KWH deliveries in the second quarter and first six months of 2006, respectively. Reduced KWH deliveries reflected milder temperatures in both periods of 2006 compared with the same periods of 2005. Those reductions were partially offset by slightly higher composite unit prices during the periods. Transmission revenues decreased by $8 million in the second quarter of 2006 and $20 million in the first six months of 2006 due to lower transmission load requirements and lower prices. The decreased loads for the first six months of 2006 (and related lower congestion revenues) resulted from milder temperatures, as demonstrated by a 40.4% decrease in cooling degree days and a 14.4% decrease in heating degree days compared to the same period in 2005, which resulted in decreased transmission expenses discussed further below. For the first six months of 2004, primarily due2006, other revenues also increased for a payment received in the first quarter of 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, which occurred. This payment was credited to higher deliveriesPenelec’s customers, resulting in all sectors. Residential and commercial revenues increased by $1 million each as a result of higher KWH deliveries, partially offset by lower composite unit prices.no net earnings effect.
Changes in kilowatt-hourKWH sales by customer class in the second quarter and first six months of 20052006 compared to the respective periods in 20042005 are summarized in the following table:
| | | Three | | Six | | | Three | | Six | | Changes in KWH Sales | | Months | | Months | | | Months | | Months | | Increase (Decrease) | | | | | | | | | | | | Retail Electric Generation: | | | | | | | | Residential | | | | (1.9 | )% | | (2.1 | )% | | Commercial | | | | - | | (0.7 | )% | | Industrial | | | | 14.8 | % | | 14.9 | % | Total Retail Electric Generation Sales | | | | 3.8 | % | | 3.3 | % | | | | | | | | | | Distribution Deliveries: | | | | | | | | | | | | Residential | | | 3.8 | % | | 1.9 | % | | | (2.1 | )% | | (2.2 | )% | | Commercial | | | (1.4 | )% | | 2.7 | % | | | (1.0 | )% | | (1.7 | )% | | Industrial | | | (8.2 | )% | | 3.7 | % | | | (0.5 | )% | | (1.8 | )% | Total Distribution Deliveries | | | (2.5 | )% | | 2.8 | % | | | (1.1 | )% | | (1.9 | )% | | | | | | | | | | | | | | |
Operating Expenses and Taxes
Total operating expenses and taxes increaseddecreased by $17$19 million or 7.3%7.5% in the second quarter of 2006 and $40$20 million or 8.4%4.0% in the first six months of 20052006 compared with the same periods in 2004.2005. The following table presents changes from the prior year by expense category:
| | | Three | | Six | | | Three | | Six | Operating Expenses and Taxes - Changes | | Months | | Months | | | Expenses Changes | | | Months | | Months | | | | (In millions) | | (In millions) | Increase (Decrease) | | | | | | | | | | | Purchased power costs | | $ | - | | $ | (6 | ) | | $ | 8 | | $ | 19 | | Other operating costs | | | 17 | | | 31 | | | | (15) | | | (30) | | Provision for depreciation | | | 1 | | | 2 | | | | (1) | | | (1) | | Amortization of regulatory assets | | | (1 | ) | | (1 | ) | | | - | | | 1 | | Deferral of new regulatory assets | | | | (12) | | | (12) | | General taxes | | | (1 | ) | | - | | | | 1 | | | 3 | | Income taxes | | | 1 | | | 14 | | | Net increase in operating expenses and taxes | | $ | 17 | | $ | 40 | | | Net decrease in expenses | | | $ | (19) | | $ | (20) | | | | | | | | | | | | | | | |
Other operatingPurchased power costs increased by $17$8 million or 36.5%5.4% in the second quarter and $31$19 million or 35.7%6.6% in the first six months of 20052006 compared to the same periods in 2004.2005. The increases in both periods were primarily dueattributable to higher unit costs from non-affiliated suppliers and increased transmission expenses in 2005 as a resultKWH purchased to meet retail generation sales requirements. These increases were partially offset by increased NUG expense deferrals of the change in the power supply agreement with FES as discussed above. In addition, there were higher costs of $2 million and $4 million associated with a low-income customer program in both the second quarter and in the first six months of 2005, respectively. Purchased power2006. Other operating costs decreased by $6 million in the first half of 2005 compared to the first half of 2004 primarily due to lower unit costs, partially offset by increased KWH purchased to meet increased retail generation sales requirements. Income taxes increasedtransmission expenses resulting from lower congestion charges. Expenses were further reduced due to higher operating incomelevels of construction activities in the second quarter and first six monthsof 2006 compared to a higher level of maintenance activities in the same period of 2005 comparedfor energy delivery operations and reliability initiatives. The deferral of new regulatory assets of $12 million reflected the May 4, 2006 PPUC approval of Penelec’s request to defer certain 2006 transmission-related costs. Penelec implemented the samedeferral accounting in the second quarter of 2006, which included $4 million for costs incurred in the first quarter of 2006 (see Regulatory Matters for further discussion). For both periods, of 2004.general taxes increased primarily due to higher Pennsylvania gross receipt taxes.
Capital Resources and Liquidity
Penelec’s cash requirements in 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 June 30, 2005,2006, Penelec had $35,000$49,000 of cash and cash equivalents compared with $36,000$35,000 as of December 31, 2004.2005. The major sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Net cashCash provided from operating activities in the second quarter and first six months of 2006 and 2005 compared with the corresponding periods in 2004, are summarizedwere as follows:
| | | Three Months Ended | | Six Months Ended | | | Six Months Ended | | | | June 30, | | June 30, | | | June 30, | Operating Cash Flows | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | | | (In millions) | | | (In millions) | | | | | | | | | | | | | | | | Cash earnings (*) | | $ | 17 | | $ | (14 | ) | $ | 45 | | $ | 29 | | | Cash earnings (1) | | | $ | 39 | | $ | 45 | | Working capital and other | | | 56 | | | 88 | | | 52 | | | 18 | | | | 1 | | | 52 | | Total cash flows from operating activities | | $ | 73 | | $ | 74 | | $ | 97 | | $ | 47 | | | | Net cash provided from operating activities | | | $ | 40 | | $ | 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. 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. The following table reconciles cash earnings with net income.
| | | Three Months Ended | | Six Months Ended | | | Six Months Ended | | | | | June 30, | | June 30, | | | June 30, | | Reconciliation of Cash Earnings | | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | | | | | (In millions) | | | (In millions) | | | | | | | | | | | | | | | | | | | Net income (GAAP) | | $ | 6 | | $ | 3 | | $ | 27 | | $ | 9 | | | $ | 39 | | $ | 27 | | | Non-cash charges (credits): | | | | | | | | | | | | | | | | | | | | | | Provision for depreciation | | | 13 | | | 11 | | | 25 | | | 23 | | | | 24 | | | 25 | | | Amortization of regulatory assets | | | 13 | | | 14 | | | 26 | | | 27 | | | | 28 | | | 26 | | | Deferral of new regulatory assets | | | | (12 | ) | | - | | | Deferred costs recoverable as regulatory assets | | | (16 | ) | | (19 | ) | | (36 | ) | | (37 | ) | | | (54 | | | (36 | ) | | Deferred income taxes and investment tax credits, net | | | - | | | (23 | ) | | 3 | | | 2 | | | | 13 | | | 3 | | | Other non-cash items | | | 1 | | | - | | | - | | | 5 | | | | 1 | | | - | | | Cash earnings (Non-GAAP) | | $ | 17 | | $ | (14 | ) | $ | 45 | | $ | 29 | | | $ | 39 | | $ | 45 | | | | | | | | | | | | | | | | | | | | | | |
Net cash provided from cash earnings increased by $31The $6 million in the second quarter and $16 million in the first six months of 2005 compared to the same periods of 2004. These increasesdecrease in cash earnings areis described above and under åResults“Results of Operationsæ.Operations.” The $32$51 million decrease infrom working capital primarily resulted from changesa decrease of $49 million in cash provided from the settlement of receivables and customer deposits, partially offset by changesa $21 million decrease in accounts payable and accrued taxes. Working capital increased by $34 million in the first six months of 2005 principally due to changes in receivables, prepayments and accrued taxes, partially offset by changesdecreased outflows of $11 million for accounts payable and customer deposits.$4 million for prepayments.
Cash Flows From Financing Activities Net cash used for financing activities was $63 million in the second quarter of 2005 compared to $61 million in the second quarter of 2004. The net change reflects a $20 million increase in common stock dividends to FirstEnergy and a $104 million increase in repayments of short-term borrowings, offset by a $122 million decrease in debt redemptions.
On May 1, 2005 Penelec redeemed all of its outstanding shares of 6.125% Series B Pollution Control Revenue Bonds at par, plus accrued interest to date of redemption.
Net cash used for financing activities was $70 million for the first six months of 2005 compared to net cash provided from financing activities ofwas $27 million in the first six months of 2004.2006 compared to net cash used for financing activities of $70 million in the first six months of 2005. The net change of $97 million reflects the absence of a $150 million long-term debt financing in 2004, a $25$63 million increase in short-term borrowings, a $30 million reduction in common stock dividendsdividend payments to FirstEnergy and a $44 million increase in repayments of short-term borrowings, offset by a $122$4 million decrease in long-term debt redemptions.
Penelec had approximately $35,000$21 million of cash and temporary investments (which includeincludes short-term notes receivable from associated companies) and approximately $205$288 million of short-term indebtedness as of June 30, 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 June 30, 2006 through 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 June 30, 2006 the facility was drawn for $67 million. In June 2006, the facility was renewed until July 28, 2007. The annual facility fee is 0.125% on the entire finance limit.
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 June 30, 2005,2006, Penelec had the capabilityability to issue $3$50 million of additional senior notes based upon FMB collateral. Penelec has no restrictions on the issuance of preferred stock.
Penelec, Funding LLC (Penelec Funding), a wholly owned subsidiary of Penelec, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penelec. Penelec Funding can borrow up to $75 million under a receivables financing arrangement. 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 June 30, 2005, the facility was drawn for $64 million. On July 15, 2005, the facility was renewed until June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.
On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility.facility which 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 andor the commitment termination date, as the same may be extended. Penelec's borrowing limit under the facility is $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 $258 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 June 30, 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 second quarterfirst six months of 20052006 was 2.93%4.86%.
Penelec’s access to capital markets and costs of financing are dependent on the ratings of its securities and that of FirstEnergy. On May 16, 2005,The ratings outlook from S&P affirmed its 'BBB-' corporate crediton all securities is stable. The ratings outlook from Moody's and Fitch on FirstEnergy Corp. and its units and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmation and outlook revision reflects the successful restart of the three nuclear units from their respective outages that occurred during the first half of 2005. S&P noted that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projected and as the nuclear operations further stabilize.
On July 18, 2005, Moody’s revised its rating outlook for FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that revision to FirstEnergy’s rating outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the outlook recognized management’s regional strategy of focusing on its core utility businesses. FirstEnergy’s credit profile has been improving, with a significant debt reduction largely resulting from the application of free cash flow. Moody’s notes that a rating upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.all securities is positive.
Cash Flows From Investing Activities Cash used for investing activities was $10 million in the second quarter of 2005 compared to $13 million in the second quarter of 2004. The increase was primarily due to increased loan repayments from associated companies, partially offset by higher property additions. Cash used for investing activities was $27 million in In the first six months of 20052006, net cash used for investing activities totaled $67 million compared to $74$27 million in the first six months of 2005. The decrease wasincrease primarily due to the absenceresulted from $27 million in 2005 of a $51 million repayment to the NUG trust fund in 2004 and increased loan repayments from associated companies, partially offset by increased property additions. Capital expendituresadditions and a $10 million increase in loans to associated companies. Expenditures for property additions primarily support Penelec’s energy delivery operations.operations and reliability initiatives.
Penelec’s capital spending for the period 2005-2007 is expected to be about $272 million for property additions and improvements, of which about $91 million applies to 2005. During the secondlast half of 2005,2006, capital requirements for property additions are expected to be about $55approximately $46 million. Penelec has additional requirements of approximately $8 millionPenelec’s capital spending for maturing long-term debt during the remainder of 2005. These cash requirements areperiod 2006-2010 is expected to be satisfied from internal cash and short-term credit arrangements.approximately $496 million, of which approximately $110 million applies to 2006. The capital spending is primarily for property additions supporting the distribution of 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 June 30, 2005, Penelec’s commodity derivatives 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. On April 1, 2006, Penelec elected to apply the normal purchase and normal sale exception to certain NUG power purchase agreements with a fair value of $14 million. A decrease of $1 million (included in “Other” in the table below) in accordance with guidance in DIG C20. The change in the fair value of this asset was recorded incommodity derivative contracts related to energy production during the second quarter and first six months of 2005 as a decrease2006 is summarized in regulatory liabilities, and therefore, had no impact on net income.the following table:
| | | Three Months Ended | | Six Months Ended | Increase (Decrease) in the Fair Value | | June 30, 2006 | | June 30, 2006 | of Commodity Derivative Contracts | | Non-Hedge | | Hedge | | Total | | Non-Hedge | | Hedge | | Total | | | | (In millions) | Change in the Fair Value of | | | | | | | | | | | | | Commodity Derivative Contracts: | | | | | | | | | | | | | | Outstanding net asset at beginning of period | | $ | 30 | | $ | - | | $ | 30 | | $ | 27 | | $ | - | | $ | 27 | | New contract value when entered | | | - | | | - | | | - | | | - | | | - | | | - | | Additions/change in value of existing contracts | | | - | | | - | | | - | | | 2 | | | - | | | 2 | | Change in techniques/assumptions | | | - | | | - | | | - | | | - | | | - | | | - | | Settled contracts | | | (4) | | | - | | | (4) | | | (3) | | | - | | | (3) | | Other | | | (14) | | | - | | | (14) | | | (14) | | | - | | | (14) | Net Assets - Derivative Contracts at End of Period (1) | | $ | 12 | | $ | - | | $ | 12 | | $ | 12 | | $ | - | | $ | 12 | | | | | | | | | | | | | | | | | | | | | Impact of Changes in Commodity Derivative Contracts(3) | | | | | | | | | | | | | | | | | | | | Income Statement effects (pre-tax) | | $ | (4) | | $ | - | | $ | (4) | | $ | (4) | | $ | - | | $ | (4) | | Balance Sheet effects: | | | | | | | | | | | | | | | | | | | | OCI (pre-tax) | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | Regulatory liability | | $ | - | | $ | - | | $ | - | | $ | 3 | | $ | - | | $ | 3 | | | | | | | | | | | | | | | | | | | | |
(1)Includes $11 million in a non-hedge commodity derivative contract which is offset by a regulatory liability. (2)Represents the increase in value of existing contracts, settled contracts and changes in techniques/assumptions.
Derivatives are included on the Consolidated Balance Sheet as of June 30, 2006 as follows:
Balance Sheet Classification | | Non-Hedge | | Hedge | | Total | | | | (In millions) | Non-Current- | | | | | | | | | | | Other deferred charges | | | 12 | | | - | | | 12 | | Other noncurrent liabilities | | | - | | | - | | | - | | | | | | | | | | | | | Net assets | | $ | 12 | | $ | - | | $ | 12 |
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of June 30, 20052006 are summarized by year in the following table:
Sources of Information - | | | | | | | | | | | | | | | | | | Fair Value by Contract Year | | | | 2005(1) | | 2006 | | 2007 | | 2008 | | 2009 | | Thereafter | | Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Prices based on external sources(2) | | | | | $ | 3 | | $ | 2 | | $ | 2 | | $ | - | | $ | - | | $ | - | | $ | 7 | | | Prices based on models | | | | | | - | | | - | | | - | | | 2 | | | 2 | | | 3 | | | 7 | | | Total | | | | | $ | 3 | | $ | 2 | | $ | 2 | | $ | 2 | | $ | 2 | | $ | 3 | | $ | 14 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) For the last two quarters of 2005. | (2) Broker quote sheets. |
Source of Information | | | | | | | | | | | | | | | | Fair Value by Contract Year | | 2006(1) | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter | | Total | | | | (In millions) | | | | | | | | | | | | | | | | | | Other external sources (2) | | $ | 3 | | $ | 3 | | $ | 2 | | $ | - | | $ | - | | $ | - | | $ | 8 | Prices based on models(3) | | | - | | | - | | | - | | | 2 | | | 2 | | | - | | | 4 | | | | | | | | | | | | | | | | | | | | | | | | Total(3) | | $ | 3 | | $ | 3 | | $ | 2 | | $ | 2 | | $ | 2 | | $ | - | | $ | 12 |
(1)For the last two quarters of 2006. (2)Broker quote sheets. (3)Includes $11 million from a non-hedge commodity derivative contract 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 June 30, 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 $59$64 million and $60$62 million as of June 30, 20052006 and December 31, 2004,2005, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6 million reduction in fair value as of June 30, 2005.2006.
Regulatory Matters
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. Penelec'sPenelec’s net regulatory assetsliabilities were approximately $135 million and $163 million as of June 30, 20052006 and December 31, 2004 were $183 million2005, respectively, and $200 million, respectively.are included under Noncurrent Liabilities on the Consolidated Balance Sheets. 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.
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. Met-Ed’s and Penelec’s combined portion of total net merger savings during 2001 - 2004 is estimated to be approximately $31.5$51 million. A procedural schedule was established by the ALJ on January 17, 2006 and the companies filed initial testimony on March 1, 2006. On May 4, 2006, the PPUC consolidated this proceeding with the April 13, 2005,10, 2006 comprehensive rate filing proceeding discussed below. Met-Ed and Penelec are unable to predict the outcome of this matter.
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 were held on June 8, 2006. On July 19, 2006, the Commonwealth Court issued an interim order inits decision affirming the remand proceeding thatPPUC’s prior orders. Although the parties should reportdecision denied the statusappeal of the negotiations to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals in MayMet-Ed and June 2005 and continue to have settlement discussions.
Penelec, purchases a portion of its PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless either 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,they had previously accounted for the portiontreatment of power supply requirements not self-suppliedcosts required by Penelec under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Penelec's exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. Penelec is authorized to defer differences between NUG contract costs and current market prices.PPUC’s October 2003 orders.
On January 12,November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism 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, filed a request with the PPUC to defer transmission-related costs beginning January 1, 2005, estimatedand FES continue to be approximately $4 million per month.involved in the FERC hearings concerning the calculation and imposition of the SECA charges. The hearing was held in May 2006. Initial briefs were submitted on June 9, 2006, and reply briefs were filed on June 27, 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 was a partywere 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 referralrefund 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. Hearings in the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial Decision was issued by the ALJ. The ALJ adopted the Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate. The ALJ recommended an April 1, 2006 effective date for this change in rate design. If the FERC accepts this recommendation, the transmission rate applicable to many load zones in PJM would increase. FirstEnergy believes that significant additional transmission revenues would have to be recovered from the JCP&L, Met-Ed and Penelec transmission zones within PJM. The Companies, as part of the Responsible Pricing Alliance, intend to submit a brief on exceptions within thirty days of the initial decision. Following submission of reply exceptions, the case is expected to be reviewed by the FERC with a decision anticipated in the fourth quarter of 2006.
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 all intervened in the case. 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, Penelec deferred approximately $12 million, representing transmission costs that were incurred from January 1, 2006 through June 30, 2006. On June 5, 2006, the OCA filed before the Commonwealth Court a petition for review of the PPUC’s approval of the deferral. On July 12, 2006, the Commonwealth Court granted the PPUC’s motion to quash the OCA’s appeal. The ratemaking treatment of the deferrals will be determined in the comprehensive rate filing proceeding discussed further below.
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 an agent for Met-Ed or Penelec in procuring the services under 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.
Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 that addresses a number of transmission, distribution and supply issues. If Penelec's preferred approach involving accounting deferrals is approved, the filing would increase annual revenues by $157 million. That filing includes, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP 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. 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, 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. The filing contemplates an increase in distribution rates for Penelec of $20 million annually. The PPUC suspended the effective date (June 10, 2006) of these rate changes for seven months after the filing as permitted under Pennsylvania law. If the PPUC adopts the overall positions taken in the intervenors’ testimony as filed, this would have a material adverse effect on the financial statements of FirstEnergy, Met-Ed and Penelec. Hearings are scheduled for late August 2006 and a PPUC decision is expected early in the first quarter of 2007.
See Note 1411 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 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.
FirstEnergy plans Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of June 30, 2006, based on estimates of the total costs of cleanup, Penelec’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities 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.pay.
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.
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, 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 websiteWeb site (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. FirstEnergy is also is proceeding with the implementation of the 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 new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, thatequipment. The 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 FirstEnergy’s 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.
OneIn addition to the above proceedings, 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. FirstEnergy filed acompany. FirstEnergy's motion to dismiss with the Courtmatter was denied on October 22, 2004. No timetable for a decision on the motionJune 2, 2006. FirstEnergy has since filed an appeal, which is pending. A responsive pleading to dismissthis matter has been established byfiled. Also, the Court. No damage estimatecomplaint has been provided and thusamended to include an additional party. No estimate of potential liability has not been determined.undertaken in this matter.
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.operations and cash flows.
New Accounting Standards and Interpretations
FSP FIN 46(R)-6 - “Determining the Variability to Be Considered in Applying FASB interpretation No. 46(R)”
In April 2006, the FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should determine the variability to be considered in applying FASB interpretation No. 46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the first quarter of 2004, consolidating VIE’s when FirstEnergy or one of its subsidiaries is determined to be the VIE’s primary beneficiary. The variability that is considered in applying interpretation 46(R) affects the determination of (a) whether the entity is a VIE; (b) which interests are variable interests in the entity; and (c) which party, if any, is the primary beneficiary of the VIE. This FSP states that the variability to be considered shall be based on an analysis of the design of the entity, involving two steps:
| Step 1: | SFAS 154 - "Accounting ChangesAnalyze the nature of the risks in the entity
| | Step 2: | Determine the purpose(s) for which the entity was created and Error Corrections - a replacement of APB Opinion No. 20determine the variability the entity is designed to create and FASB Statement No. 3"pass along to its interest holders. |
In May 2005,After determining the FASB issued SFAS 154variability to changeconsider, the requirements for accounting and reporting a changeenterprise can determine which interests are designed to absorb that variability. The guidance in accounting principle. It appliesthis FSP is applied prospectively to all voluntary changes in accounting principleentities (including newly created entities) with which that enterprise first becomes involved and to changesall entities previously required by an accounting pronouncementto be analyzed under interpretation 46(R) when that pronouncementa reconsideration event has occurred after July 1, 2006. Penelec does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances,expect this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and thathave a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement ofmaterial impact on its financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Penelec will adopt this Statement effective January 1, 2006.statements.
FIN 47, "Accounting48 - “Accounting for Conditional Asset Retirement ObligationsUncertainty in Income Taxes - an interpretation of FASB Statement No. 143"109.”
On March 30, 2005,In June 2006, the FASB issued FIN 4748 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to clarify the scopebe taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and timingtransition. The evaluation of liability recognition for conditional asset retirement obligations. Undera tax position in accordance with this interpretation companies are requiredwill be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit 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.financial statements. This Interpretationinterpretation is effective no later than the end offor fiscal years endingbeginning after December 15, 2005. Therefore, Penelec will adopt this Interpretation in the fourth quarter of 2005.2006. Penelec is currently evaluating the effectimpact of this Interpretation will have on its financial statements.Statement.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"SUBSEQUENT EVENTS
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 indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, Penelec continues to evaluate its investments as required by existing authoritative guidance.Pennsylvania Law Change
On July 12, 2006, the Governor of Pennsylvania signed House Bill 859, which increases the net operating loss deduction allowed for the corporate net income tax from $2 million to $3 million, or the greater of 12.5% of taxable income. As a result, Penelec expects to recognize a net operating loss benefit of $2.2 million (net of federal tax benefit) in the third quarter of 2006.
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 the 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 in timely alerting themand were designed to anybring to their attention material information relating to the registrants’registrant and theirits consolidated subsidiaries that is required to be included in the registrants’ periodic reports and in ensuring that information required in the reports filed under the Exchange Act is recorded, processed summarized and reportedby others within the time period specified by the SEC's rules and forms.those entities.
(b) CHANGES IN INTERNAL CONTROLS
On April 1, 2005, FirstEnergy,During the Ohio Companies and Penn implemented or modified certain internal controls over financial reporting to accommodate their participation in the launch of the MISO Day 2 wholesale energy markets for both day-ahead and real-time energy transmissions, as well as a financial transmission rights market for transmission capacity. MISO also started dispatching generating plants and providing real-time energy and balance services. The new or modified controls primarily relate to revenue and cost recognition associated with power sales and purchases in the MISO Day 2 markets. Management believes these controls are important for the accurate reporting of such amounts and, based upon management's testing, are adequate for such purposes. Therequarter ended June 30, 2006, there were no other 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 during the quarter ended June 30, 2005.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 1310 and 1411 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. ITEM 1A.RISK FACTORS See Item 1A RISK FACTORS in Part I of the Form 10-K for the year ended December 31, 2005 for a discussion of the risk factors of FirstEnergy and the subsidiary registrants. For the quarter ended June 30, 2006, there have been no material changes to these risk factors.
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 | | | | | | | | | | | | | | April 1-30, 2005 | | | 449,813 | | $ | 42.53 | | | - | | | - | | | May 1-31, 2005 | | | 940,490 | | $ | 43.75 | | | - | | | - | | | June 1-30, 2005 | | | 1,103,335 | | $ | 46.34 | | | - | | | - | | | | | | | | | | | | | | | | | | Second Quarter 2005 | | | 2,493,638 | | $ | 44.68 | | | - | | | - | |
| | | Period | | | | April 1-30, | | | May 1-31, | | | June 1-30, | | | Second | | | | | 2006 | | | 2006 | | | 2006 | | | Quarter | Total Number of Shares Purchased (a) | | | 132,910 | | | 481,150 | | | 470,009 | | | 1,084,069 | | Average Price Paid per Share | | $ | 49.82 | | $ | 52.26 | | $ | 53.10 | | $ | 52.33 | | 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. |
(b) | | (b) | On June 20, 2006, FirstEnergy Corp. announced that its Board of Directors has authorized a share repurchase program for up to 12 million shares of common stock. At management’s discretion, shares may be acquired on the open market or through privately negotiated transactions, subject to market conditions and other factors. The Board’s authorization of the repurchase program does not currently haverequire FirstEnergy to purchase any publicly announced plan orshares and the program for share purchases.may be terminated at any time. |
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
| (a) | The annual meeting of FirstEnergy shareholders was held on May 17, 2005.16, 2006. |
| (b) | At this meeting, the following persons were elected to FirstEnergy's Board of Directors:Directors for one-year terms: |
| | | Number of Votes | | Number of Votes | | | | For | | Withheld | | For | | Withheld | | | | | | | | | | | | Anthony J. Alexander | | | 280,505,194 | | 5,433,413 | | | 193,156,658 | | 90,938,042 | | Dr. Carol A. Cartwright | | | 164,744,513 | | 119,350,187 | | William T. Cottle | | | 183,961,100 | | 100,133,600 | | Robert B. Heisler, Jr. | | | 268,681,345 | | 15,413,355 | | Russell W. Maier | | | 279,922,948 | | 6,015,659 | | | 186,309,666 | | 97,785,034 | | Robert N. Pokelwaldt | | | 280,048,373 | | 5,890,234 | | | | George M. Smart | | | 183,516,902 | | 100,577,798 | | Wes M. Taylor | | | 283,540,631 | | 2,397,976 | | | 186,519,704 | | 97,574,996 | | Jesse T. Williams, Sr. | | | 279,999,208 | | 5,939,399 | | | 185,540,843 | | 98,553,857 |
The term of office for the following Directors continued after the shareholders meeting: Dr. Carol A. Cartwright, William T. Cottle, Paul J. Powers, George M. Smart, Dr. Patricia K. Woolf,meeting and expires in 2007: Paul T. Addison, Ernest J. Novak, Jr., Catherine A. Rein and Robert C. Savage. The following Directors retired from the Board effective May 16, 2006: Robert N. Pokelwaldt, Paul J. Powers and Dr. Patricia K. Woolf.
(c) | (i) | At this meeting, the appointment of PricewaterhouseCoopers LLP, an independent registered public accounting firm, as auditor for the year 2004 was ratified: |
Number of Votes
| | For
| | Against
| | Abstentions
| | | | | | | | 281,532,886
| | | 1,685,722
| | | 2,719,999
| |
| (ii) | At this meeting, a shareholder proposal requesting that FirstEnergy publish semi-annual reports regarding its political contributions was not approved (approval required a majority of votes cast): |
Number of Votes(c)(i)At this meeting, the appointment of PricewaterhouseCoopers LLP, an independent registered public accounting firm, as auditor for the year 2006 was ratified:
| | | | | | | | Broker
| | For
| | Against
| | Abstentions
| | Non-Votes
| | | | | | | | | | 19,941,051
| | | 215,630,919
| | | 19,307,851
| | | 31,058,786
| |
| (iii) | At this meeting, a shareholder proposal recommending that the Board of Directors take steps for adoption of simple majority voting was approved (approval required a majority of votes cast): |
Number of Votes | For | | Against | | Abstentions | | | | | | | | 278,799,686 | | | 2,661,331 | | | 2,633,683 |
Number of Votes
| | | | | | | Broker
| | For
| | Against
| | Abstentions
| | Non-Votes
| | | | | | | | | | 178,017,001
| | | 71,654,202
| | | 5,208,721
| | | 31,058,683
| |
(ii)At this meeting, a shareholder proposal recommending that the Board of Directors adopt simple majority shareholder voting and make it applicable to the greatest number of governance issues practicable was approved (approval required a favorable vote of a majority of the votes cast):
Number of Votes | | | | | | | | Broker | For | | Against | | Abstentions | | Non-Votes | | | | | | | | | | 184,910,522 | | | 67,099,919 | | | 4,832,226 | | | 27,252,033 |
Based on this result, the Board of Directors will further review this proposal and consider the appropriate steps to take in response.
| (iv) | At this meeting, a shareholder proposal recommending that any matching awards under the Executive Deferred Compensation Plan be in the form of performance-based stock options was not approved (approval required a majority of the votes cast): |
(iii)At this meeting, a shareholder proposal urging the Board of Directors to seek shareholder approval of future severance agreements with senior executives that provide benefits in an amount exceeding 2.99 times the sum of the executives' base salary plus bonus was not approved (approval required a favorable vote of a majority of the votes cast):
Number of Votes
| | | | | | | | Broker
| | For
| | Against
| | Abstentions
| | Non-Votes
| | | | | | | | | | 47,687,400
| | | 202,204,312
| | | 4,988,404
| | | 31,058,491
| |
Number of Votes | | | | | | | | Broker | For | | Against | | Abstentions | | Non-Votes | | | | | | | | | | 123,673,866 | | | 128,388,870 | | | 4,780,131 | | | 27,251,833 |
ITEM 6. EXHIBITS
(a)Exhibits
Exhibit Number | | Number
| | | | | | JCP&L
| | | | | | 12 | Fixed charge ratios | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | | 31.3 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(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-15(e). | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | PenelecFirstEnergy
| | | | | | | | 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-15(e)15d-(e). | | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e)15d-(e). | | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | | | FirstEnergyOE
| | | | | | | 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. | | | 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-15(e)15d-(e). | | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e)15d-(e). | | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | | | OECEI
| | | | | | | 4.1 | Seventy-ninth Supplemental Indenture dated as of April 1, 2005 between OE and The Bank of New York, as successor Trustee under the Indenture dated as of August 1, 1930. |
| 4.2 | Eightieth Supplemental Indenture dated as of April 15, 2005 between OE and The Bank of New York, as successor Trustee under the Indenture dated as of August 1, 1930.
| | 4.3 | Eighty-first Supplemental Indenture dated as of June 1, 2005 between OE and The Bank of New York, as successor Trustee under the Indenture dated as of August 1, 1930.
| | 4.4 | Eleventh Supplemental Indenture dated as of April 1, 2005 between OE and The Bank of New York, as Trustee under the General Mortgage Indenture and Deed of Trust dated as of January 1, 1998.
| | 4.5 | Twelfth Supplemental Indenture dated as of April 15, 2005 between OE and The Bank of New York, as Trustee under the General Mortgage Indenture and Deed of Trust dated as of January 1, 1998.
| | 4.6 | Thirteenth Supplemental Indenture dated as of June 1, 2005 between OE and The Bank of New York, as Trustee under the General Mortgage Indenture and Deed of Trust dated as of January 1, 1998.
| | 10.1 | OE Nuclear Capital Contribution Agreement by and between Ohio Edison Company and | | | FirstEnergy Nuclear Generation Corp. (May 20, 2005 Form 8-K, Exhibit 10.1).
| | 10.2 | OE Fossil Purchase and Sale Agreement by and between Ohio Edison Company (Seller) and | | | FirstEnergy Generation Corp. (Purchaser). (May 20, 2005 Form 8-K, Exhibit 10.2).
| | 15 | Letter from independent registered public accounting firm | | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e)15d-(e). | | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-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. | | | | | PennJCP&L
| | | | | | | | 10.112 | PP Nuclear SubscriptionFixed 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 Capital Contribution Agreement by and between Pennsylvania Powerchief financial officer, pursuant to 18 U.S.C. Section 1350. | | | | Company and FirstEnergy Nuclear Generation Corp. (May 20, 2005 Form 8-K, Exhibit 10.1).
| Met-Ed | 10.2 | PP Fossil Purchase and Sale Agreement by and between Pennsylvania Power Company (Seller) | | | | and FirstEnergy Generation Corp. (Purchaser). (May 20, 2005 Form 8-K, Exhibit 10.2).
| | | 1512 | Letter from independent registered public accounting firm.Fixed charge ratios | | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e)15d-(e). | | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e)15d-(e). | | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | | | CEIPenelec
| | | | | | | | 4.112 | Eighty-seventh Supplemental Indenture dated as of April 1, 2005 between CEI and JPMorgan Chase Bank, N.A., as Trustee under the Mortgage and Deed of Trust dated as of July 1, 1940.
Fixed charge ratios | | | 4.215 | Eighty-eighth Supplemental Indenture dated as of July 1, 2005 between CEI and JPMorgan Chase Bank, N.A., as Trustee under the Mortgage and Deed of Trust dated as of July 1, 1940.
| | 10.1 | CEI Nuclear Purchase and Sale Agreement by and between The Cleveland Electric Illuminating | | | Exhibit 10.1).
| | 10.2 | CEI Fossil Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company | | | (Seller) and FirstEnergy Generation Corp. (Purchaser). (May 20, 2005 Form 8-K, Exhibit 10.2).
Letter from independent registered public accounting firm | | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e)15d-(e). | | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. | | | | TE
| | | | | | 4.1 | Fifty-fifth Supplemental Indenture dated as of April 1, 2005 between TE and JPMorgan Chase Bank, N.A., as Trustee under the Indenture of Mortgage and Deed of Trust dated as of April 1, 1947.
| | 10.1 | TE Nuclear Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Nuclear Generation Corp. (Purchaser). (May 20, 2005 Form 8-K, Exhibit 10.1).
| | 10.2 | TE Fossil Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (May 20, 2005 Form 8-K, Exhibit 10.2).
| | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e)15d-(e). | | | 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. |
Pursuant to reporting requirements of respective financings, 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.
August 1, 2005
7, 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/ /s/ Harvey L. Wagner
| | | Harvey L. Wagner | | | Vice President, Controller | | | and Chief Accounting Officer |
|