Washington, D. C. 20549
Amendment No. 1
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer,” “accelerated filer” and “smaller reporting company" in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
This combined Form 10-Q/A is separately filed by Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company and Pennsylvania Electric Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf.
Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company and Pennsylvania Electric Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q/A with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.
The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on the registrants’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. Also, a security rating is not a recommendation to buy, sell or hold securities, and it may be subject to revision or withdrawal at any time and each such rating should be evaluated independently of any other rating. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events or otherwise.
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:
GLOSSARY OF TERMS, Cont’d.
GLOSSARY OF TERMS, Cont’d.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and its subsidiaries FGCO and NGC, and FESC.
FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the 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, 2007 for FirstEnergy, FES and the Utilities. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utilities reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.
FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 9) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.
OE, CEI, TE and Penelec are restating their respective Consolidated Statements of Cash Flows for the nine months ended September 30, 2008 and 2007, to correct common stock dividend payments reported in cash flows from financing activities. The consolidated statements of cash flows, as originally filed, erroneously reflected the dividends declared in the third quarter of 2008 and the third quarter of 2007 applicable to future quarters' payments as dividends paid in the quarter that they were declared. The corrections resulted in a corresponding change in operating liabilities - accounts payable, included in cash flows from operating activities.
This correction does not affect the respective registrants’ previously reported consolidated statements of income and comprehensive income for the three months and nine ended September 30, 2008 and 2007, and consolidated balance sheets as of September 30, 2008 and December 31, 2007 contained in the combined Form 10-Q for the quarter ended September 30, 2008, as originally filed on November 7, 2008.
The effects of the corrections on OE’s, CEI’s, TE’s and Penelec’s Consolidated Statements of Cash Flows for the nine months ended September 30, 2008 and 2007 are as follows:
2. EARNINGS PER SHARE
Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock 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. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an accelerated share repurchase program at an initial price of approximately $900 million. A final purchase price adjustment of $51 million was settled in cash on December 13, 2007. The following table reconciles basic and diluted earnings per share of common stock:
| | | Three Months | | Nine Months | |
| | | | | | |
| Reconciliation of Basic and Diluted Earnings per Share | | 2008 | | 2007 | | 2008 | | 2007 | |
| | | (In millions, except per share amounts) | |
| | | | | | | | | | | | | | |
| Net income | | $ | 471 | | $ | 413 | | $ | 1,010 | | $ | 1,041 | |
| | | | | | | | | | | | | | |
| Average shares of common stock outstanding – Basic | | | 304 | | | 304 | | | 304 | | | 307 | |
| Assumed exercise of dilutive stock options and awards | | | 3 | | | 3 | | | 3 | | | 4 | |
| Average shares of common stock outstanding – Dilutive | | | 307 | | | 307 | | | 307 | | | 311 | |
| | | | | | | | | | | | | | |
| Basic earnings per share | | $ | 1.55 | | $ | 1.36 | | $ | 3.32 | | $ | 3.39 | |
| Diluted earnings per share | | $ | 1.54 | | $ | 1.34 | | $ | 3.29 | | $ | 3.35 | |
3. GOODWILL
In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and more frequently as indicators of impairment arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment is indicated, FirstEnergy recognizes a loss – calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill.
FirstEnergy's 2008 annual review was completed in the third quarter of 2008 with no impairment indicated. As discussed in Note 12(B), the Ohio Companies filed a comprehensive ESP and MRO with the PUCO on July 31, 2008. The annual goodwill impairment analysis assumed management's best estimate of the outcome of those filings. There was no impairment indicated for FirstEnergy and the Ohio Companies based on a probability-weighted outcome of the ESP and MRO proceedings. If the PUCO’s final decision authorizes less revenue recovery than the amounts assumed, an additional impairment analysis would be performed at that time that could result in future goodwill impairment.
FirstEnergy's goodwill primarily relates to its energy delivery services segment. In the first and third quarters of 2008, FirstEnergy adjusted goodwill by $1 million and $23 million, respectively, of the former GPU companies due to the realization of tax benefits that had been reserved under purchase accounting. The following tables reconcile changes to goodwill for the three months and nine months ended September 30, 2008.
| | | | | | | | | | | | | | | |
| | | (In millions) | |
Balance as of July 1, 2008 | | | | | | | | | | | | | | | | | | | | | | |
Adjustments related to GPU acquisition | | | | | | - | | | | | | | | | | | | | | | | |
Balance as of September 30, 2008 | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | |
Balance as of January 1, 2008 | | | | | | | | | | | | | | | | | | | | | | |
Adjustments related to GPU acquisition | | | | | | - | | | | | | | | | | | | | | | | |
Balance as of September 30, 2008 | | | | | | | | | | | | | | | | | | | | | | |
4. DIVESTITURES AND DISCONTINUED OPERATIONS
On March 7, 2008, FirstEnergy sold certain telecommunication assets, resulting in a net after-tax gain of $19.3 million. The sale of assets did not meet the criteria for classification as discontinued operations as of September 30, 2008.
5. FAIR VALUE MEASURES
Effective January 1, 2008, FirstEnergy adopted SFAS 157, which provides a framework for measuring fair value under GAAP and, among other things, requires enhanced disclosures about assets and liabilities recognized at fair value. FirstEnergy also adopted SFAS 159 on January 1, 2008, which provides the option to measure certain financial assets and financial liabilities at fair value. FirstEnergy has analyzed its financial assets and financial liabilities within the scope of SFAS 159 and, as of September 30, 2008, has elected not to record eligible assets and liabilities at fair value.
As defined in SFAS 157, fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that are held in various trusts.
Level 2 – Pricing inputs are either directly or indirectly observable in the market as of the reporting date, other than quoted prices in active markets included in Level 1. FirstEnergy’s Level 2 assets and liabilities consist primarily of investments in debt securities held in various trusts and commodity forwards. Additionally, Level 2 includes those financial instruments that are valued using models or other valuation methodologies based on assumptions that are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Instruments in this category include non-exchange-traded derivatives such as forwards and certain interest rate swaps.
Level 3 – Pricing inputs include inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. FirstEnergy develops its view of the future market price of key commodities through a combination of market observation and assessment (generally for the short term) and fundamental modeling (generally for the longer term). Key fundamental electricity model inputs are generally directly observable in the market or derived from publicly available historic and forecast data. Some key inputs reflect forecasts published by industry leading consultants who generally employ similar fundamental modeling approaches. Fundamental model inputs and results, as well as the selection of consultants, reflect the consensus of appropriate FirstEnergy management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. FirstEnergy’s Level 3 instruments consist of NUG contracts.
FirstEnergy utilizes market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs.
The following table sets forth FirstEnergy’s financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of September 30, 2008. As required by SFAS 157, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
| | | September 30, 2008 | |
| Recurring Fair Value Measures | | Level 1 | | Level 2 | | Level 3 | | Total | |
| | | (In millions) | |
| Assets: | | | | | | | | | | | | | |
| Derivatives | | $ | - | | $ | 45 | | $ | - | | $ | 45 | |
| Nuclear decommissioning trusts | | | 761 | | | 1,112 | | | - | | | 1,873 | |
| Other investments | | | 19 | | | 312 | | | - | | | 331 | |
| Total | | $ | 780 | | $ | 1,469 | | $ | - | | $ | 2,249 | |
| | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | |
| Derivatives | | $ | 8 | | $ | 19 | | $ | - | | $ | 27 | |
NUG contracts(1) | | | - | | | - | | | 603 | | | 603 | |
| Total | | $ | 8 | | $ | 19 | | $ | 603 | | $ | 630 | |
| (1) | NUG contracts are completely offset by regulatory assets. |
The determination of the above fair value measures takes into consideration various factors required under SFAS 157. These factors include the credit standing of the counterparties involved, the impact of credit enhancements (such as cash deposits, LOCs and priority interests) and the impact of nonperformance risk.
Exchange-traded derivative contracts, which include some futures and options, are generally based on unadjusted quoted market prices in active markets and are classified within Level 1. Forwards, options and swap contracts that are not exchange-traded are classified as Level 2 as the fair values of these items are based on Intercontinental Exchange quotes or market transactions in the OTC markets. In addition, complex or longer-term structured transactions can introduce the need for internally-developed model inputs that may not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is classified as Level 3.
Nuclear decommissioning trusts consist of equity securities listed on active exchanges classified as Level 1 and various debt securities and collective trusts classified as Level 2. Other investments represent the NUG trusts, spent nuclear fuel trusts and rabbi trust investments, which primarily consist of various debt securities and collective trusts classified as Level 2.
The following tables provide a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three and nine months ended September 30, 2008:
| | | Three Months | | | Nine Months | |
| | | (In millions) | |
| Balance at beginning of period | | $ | 644 | | | $ | 750 | |
Realized and unrealized gains (losses)(1) | | | (32 | ) | | | (120 | ) |
Purchases, sales, issuances and settlements, net(1) | | | (9 | ) | | | (27 | ) |
| Net transfers to (from) Level 3 | | | - | | | | - | |
| Balance as of September 30, 2008 | | $ | 603 | | | $ | 603 | |
| | | | | | | | | |
| Change in unrealized gains (losses) relating to | | | | | | | | |
| instruments held as of September 30, 2008 | | $ | (32 | ) | | $ | (120 | ) |
(1) Changes in the fair value of NUG contracts are completely offset by regulatory assets and do not impact earnings | |
Under FSP FAS 157-2, “Effective Date of FASB Statement No. 157”, FirstEnergy deferred until January 1, 2009, the election of SFAS 157 for financial assets and financial liabilities measured at fair value on a non-recurring basis and is currently evaluating the impact of SFAS 157 on those financial assets and financial liabilities.
6. 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 derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight for risk management activities throughout FirstEnergy. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.
FirstEnergy accounts for derivative instruments in its Consolidated Balance Sheet at their fair value unless they meet the criteria for the normal purchases and normal sales exception. Derivatives that meet those criteria are accounted for at cost. FirstEnergy regularly assesses derivatives based on the normal purchases and normal sales criteria and expects no changes in eligibility for the normal purchases and normal sales exception. The changes in the fair value of derivative instruments that do not meet the normal purchases and normal sales exception are recorded as other expense, as 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, the nature of the hedge transaction and hedge effectiveness. FirstEnergy does not offset fair value for the right to reclaim collateral or the obligation to return collateral.
FirstEnergy hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity, natural gas and other commodity 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 recognized directly in net income.
The net deferred losses of $64 million included in AOCL as of September 30, 2008, for derivative hedging activity, as compared to $75 million as of December 31, 2007, resulted from a net $3 million increase related to current hedging activity and a $14 million decrease due to net hedge losses reclassified to earnings during the nine months ended September 30, 2008. Based on current estimates, approximately $16 million (after tax) of the net deferred losses on derivative instruments in AOCL as of September 30, 2008 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors, including commodity prices, counterparty credit and interest rates.
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. In order to reduce counterparty exposure and lessen variable debt exposure under current market conditions, FirstEnergy unwound its remaining interest rate swaps. During the first nine months of 2008, FirstEnergy received $3 million to terminate interest rate swaps with an aggregate notional value of $250 million. As of September 30, 2008, FirstEnergy has no outstanding interest rate swaps hedging fixed-rate long term debt.
During 2007 and the first nine months of 2008, 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 issuance of variable-rate short-term debt and fixed-rate long-term debt securities, by one or more of its subsidiaries, as outstanding debt matures during 2008 and 2009. 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 and LIBOR rates between the date of hedge inception and the date of the debt issuance. FirstEnergy considers counterparty credit and nonperformance risk in its hedge assessments and continues to expect the forward-starting swaps to be effective in protecting against the risk of changes in future interest payments. During the first nine months of 2008, FirstEnergy terminated swaps with a notional value of $750 million and entered into swaps with a notional value of $950 million. FirstEnergy paid $16 million related to the terminations, $5 million of which was deemed ineffective and recognized in current period earnings. FirstEnergy will recognize the remaining loss over the life of the associated future debt. As of September 30, 2008, FirstEnergy had forward swaps with an aggregate notional amount of $600 million and a fair value of $(0.2) million.
7. ASSET RETIREMENT OBLIGATIONS
FirstEnergy has recognized applicable legal obligations under SFAS 143 for nuclear power plant decommissioning, reclamation of a sludge disposal pond 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.
The ARO of $1.3 billion as of September 30, 2008 is primarily related to the future nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.
FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of September 30, 2008, the fair value of the decommissioning trust assets was approximately $1.9 billion.
The following tables analyze changes to the ARO balance during the three months and nine months ended September 30, 2008 and 2007, respectively.
| ARO Reconciliation | | FirstEnergy | | FES | | OE | | CEI | | TE | | JCP&L | | Met-Ed | | Penelec | |
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Revisions in estimated cash flows | | | | ) | | | | | | ) | | | | | | | | | | | | | | | |
Balance, September 30, 2008 | | | | | | | | | | | | | | | | | | | | | | | | | |
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Revisions in estimated cash flows | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance, September 30, 2007 | | | | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | |
| ARO Reconciliation | | FirstEnergy | | FES | | OE | | CEI | | TE | | JCP&L | | Met-Ed | | Penelec | |
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Revisions in estimated cash flows | | | | ) | | | | | | ) | | | | | | | | | | | | | | | |
Balance, September 30, 2008 | | | | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | |
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Revisions in estimated cash flows | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance, September 30, 2007 | | | | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | |
8. PENSION AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its subsidiaries’ employees. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December 31, 2007. 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 pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
The components of FirstEnergy's net periodic pension cost and other postretirement benefit cost (including amounts capitalized) for the three months and nine months ended September 30, 2008 and 2007, consisted of the following:
| | | Three Months | | Nine Months | |
| | | Ended September 30 | | Ended September 30 | |
| Pension Benefits | | 2008 | | 2007 | | 2008 | | 2007 | |
| | | (In millions) | |
| Service cost | | $ | 21 | | $ | 21 | | $ | 62 | | $ | 63 | |
| Interest cost | | | 72 | | | 71 | | | 217 | | | 213 | |
| Expected return on plan assets | | | (116 | ) | | (112 | ) | | (347 | ) | | (337 | ) |
| Amortization of prior service cost | | | 3 | | | 2 | | | 7 | | | 7 | |
| Recognized net actuarial loss | | | 1 | | | 10 | | | 4 | | | 31 | |
| Net periodic cost (credit) | | $ | (19 | ) | $ | (8 | ) | $ | (57 | ) | $ | (23 | ) |
| | | Three Months | | Nine Months | |
| | | Ended September 30 | | Ended September 30 | |
| Other Postretirement Benefits | | 2008 | | 2007 | | 2008 | | 2007 | |
| | | (In millions) | |
| Service cost | | $ | 5 | | $ | 5 | | $ | 14 | | $ | 16 | |
| Interest cost | | | 18 | | | 17 | | | 55 | | | 52 | |
| Expected return on plan assets | | | (13 | ) | | (12 | ) | | (38 | ) | | (38 | ) |
| Amortization of prior service cost | | | (37 | ) | | (37 | ) | | (111 | ) | | (112 | ) |
| Recognized net actuarial loss | | | 12 | | | 11 | | | 35 | | | 34 | |
| Net periodic cost (credit) | | $ | (15 | ) | $ | (16 | ) | $ | (45 | ) | $ | (48 | ) |
Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. FES and the Utilities capitalize employee benefits related to construction projects. The net periodic pension costs and net periodic postretirement benefit costs (including amounts capitalized) recognized by FES and each of the Utilities for the three months and nine months ended September 30, 2008 and 2007 were as follows:
| | | Three Months | | Nine Months | |
| | | Ended September 30 | | Ended September 30 | |
| Pension Benefit Cost (Credit) | | 2008 | | 2007 | | 2008 | | 2007 | |
| | | (In millions) | |
| FES | | $ | 4 | | $ | 5 | | $ | 11 | | $ | 16 | |
| OE | | | (6 | ) | | (4 | ) | | (20 | ) | | (12 | ) |
| CEI | | | (1 | ) | | - | | | (3 | ) | | 1 | |
| TE | | | (1 | ) | | - | | | (2 | ) | | - | |
| JCP&L | | | (4 | ) | | (2 | ) | | (11 | ) | | (7 | ) |
| Met-Ed | | | (3 | ) | | (2 | ) | | (8 | ) | | (5 | ) |
| Penelec | | | (3 | ) | | (2 | ) | | (10 | ) | | (8 | ) |
| Other FirstEnergy subsidiaries | | | (5 | ) | | (3 | ) | | (14 | ) | | (8 | ) |
| | | $ | (19 | ) | $ | (8 | ) | $ | (57 | ) | $ | (23 | ) |
| | | Three Months | | Nine Months | |
| | | Ended September 30 | | Ended September 30 | |
| Other Postretirement Benefit Cost (Credit) | | 2008 | | 2007 | | 2008 | | 2007 | |
| | | (In millions) | |
| FES | | $ | (2 | ) | $ | (2 | ) | $ | (5 | ) | $ | (7 | ) |
| OE | | | (2 | ) | | (3 | ) | | (5 | ) | | (8 | ) |
| CEI | | | 1 | | | 1 | | | 2 | | | 3 | |
| TE | | | 1 | | | 1 | | | 3 | | | 4 | |
| JCP&L | | | (4 | ) | | (4 | ) | | (12 | ) | | (12 | ) |
| Met-Ed | | | (3 | ) | | (3 | ) | | (8 | ) | | (8 | ) |
| Penelec | | | (3 | ) | | (3 | ) | | (10 | ) | | (10 | ) |
| Other FirstEnergy subsidiaries | | | (3 | ) | | (3 | ) | | (10 | ) | | (10 | ) |
| | | $ | (15 | ) | $ | (16 | ) | $ | (45 | ) | $ | (48 | ) |
Under the Pension Protection Act of 2006, companies are generally required make a scheduled series of contributions to fund 100% of outstanding qualified pension benefit obligations over a seven year period. As of December 31, 2007, FirstEnergy’s pension plan was overfunded, and, therefore, FirstEnergy will not be required to make any contributions in 2009 for the 2008 plan year. However, the overall actual asset return as of December 31, 2008 may reduce the value of the pension plan’s assets to the level where contributions would be required in 2010 for the 2009 plan year.
9. VARIABLE INTEREST ENTITIES
FIN 46R addresses the consolidation of VIEs, including special-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the entity's residual economic risks and rewards. FirstEnergy and its subsidiaries consolidate a VIE when they are determined to be the VIE's primary beneficiary as defined by FIN 46R.
Mining Operations
On July 16, 2008, FirstEnergy Ventures Corp., a subsidiary of FirstEnergy, entered into a joint venture with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake in the Signal Peak mining and coal transportation operations near Roundup, Montana. FirstEnergy made a $125 million equity investment in the joint venture, which acquired 80% of the mining operations (Signal Peak Energy, LLC) and 100% of the transportation operations, with FirstEnergy Ventures Corp. owning a 45% economic interest and an affiliate of the Boich Companies owning a 55% economic interest in the joint venture. Both parties have a 50% voting interest in the joint venture. After January 2010, the joint venture will have 18 months to exercise an option to acquire the remaining 20% stake in the mining operations. In accordance with FIN 46R, FirstEnergy is including the limited liability companies created for the mining and transportation operations of this joint venture in its consolidated financial statements.
Trusts
FirstEnergy’s consolidated financial statements include PNBV and Shippingport, 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 3% equity interest by an unaffiliated third party and a 3% 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.
Loss Contingencies
FES and the Ohio Companies are exposed to losses under their applicable sale and leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments are made. The following table shows each company’s net exposure to loss based upon the casualty value provisions mentioned above as of September 30, 2008:
| | | Maximum Exposure | | Discounted Lease Payments, net | | Net Exposure |
| | | (in millions) |
| FES | | $ | 1,363 | | $ | 1,209 | | $ | 154 |
| OE | | 788 | | 597 | | 191 |
| CEI | | 718 | | 79 | | 639 |
| TE | | 718 | | 421 | | 297 |
In October 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO, which assumed all of CEI’s and TE’s obligations arising under those leases. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCO’s leasehold interests under its July 2007 Bruce Mansfield Unit 1 sale and leaseback transaction to a newly formed wholly-owned subsidiary in December 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE will remain primarily liable on the 1987 leases and related agreements as to the lessors and other parties to the agreements. FGCO remains primarily liable on the 2007 leases and related agreements, and FES remains primarily liable as a guarantor under the related 2007 guarantees, as to the lessors and other parties to the respective agreements. These assignments terminate automatically upon the termination of the underlying leases.
During the second quarter of 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant and approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. Also in the second quarter of 2008, NGC purchased 158.5 MW of lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2, which purchases were undertaken in connection with the previously disclosed exercise of the periodic purchase option provided in the TE and CEI sale and leaseback arrangements. The Ohio Companies continue to lease these MW under the respective sale and leaseback arrangements and the related lease debt remains outstanding.
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 Utilities 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 entered 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 eight 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 eight 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 eight 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.
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 may incur for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs from these entities during the three months and nine months ended September 30, 2008 and 2007 are shown in the following table:
| | | Three Months Ended | | Nine Months Ended | |
| | | September 30 | | September 30 | |
| | | 2008 | | 2007 | | 2008 | | 2007 | |
| | | (In millions) | |
| JCP&L | | $ | 26 | | $ | 30 | | $ | 67 | | $ | 71 | |
| Met-Ed | | | 12 | | | 13 | | | 44 | | | 40 | |
| Penelec | | | 8 | | | 7 | | | 25 | | | 22 | |
| Total | | $ | 46 | | $ | 50 | | $ | 136 | | $ | 133 | |
Transition Bonds
The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. In June 2002, JCP&L Transition Funding 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. In August 2006, JCP&L Transition Funding II sold $182 million of transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS.
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. As of September 30, 2008, $377 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets - principally bondable transition property.
Bondable transition property under New Jersey law represents the irrevocable right of a utility company to charge, collect and receive from its customers, through a non-bypassable transition bond charge (TBC), the principal amount and interest on transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate quarterly servicing fees of $157,000 payable from TBC collections.
10. INCOME TAXES
FirstEnergy accounts for uncertainty in income taxes recognized in a company’s financial statements in accordance with FIN 48. This interpretation prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. FIN 48 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 is a two-step process. The first step is to determine if it is more likely than not that a tax position will be sustained upon examination, based on the merits of the position, and should therefore be recognized. The second step is to measure a tax position that meets the more likely than not recognition threshold to determine the amount of income tax benefit to recognize in the financial statements.
Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate, if recognized in 2008. The majority of items that would not affect the 2008 effective tax rate would be purchase accounting adjustments to goodwill, if recognized in 2008. Upon completion of the federal tax examinations for tax years 2004 to 2006 in the third quarter of 2008, FirstEnergy recognized approximately $45 million in tax benefits, including $5 million that favorably affected FirstEnergy’s effective tax rate. A majority of the tax benefits recognized in the third quarter of 2008 adjusted goodwill as a purchase accounting adjustment ($20 million) and accumulated deferred income taxes for temporary tax items ($15 million). During the first nine months of 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of September 30, 2008, FirstEnergy expects that it is reasonably possible that approximately $151 million of the unrecognized benefits may be resolved within the next twelve months, of which $54 million to $147 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs capital gains and losses recognized on the disposition of assets and various other tax items.
FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. The reversal of accrued interest associated with the $45 million in recognized tax benefits favorably affected FirstEnergy’s effective tax rate by $12 million in the third quarter and first nine months of 2008 and an interest receivable of $4 million was removed from the accrued interest for FIN 48 items. The net amount of interest accrued as of September 30, 2008 was $56 million, as compared to $53 million as of December 31, 2007.
FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2007. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audits for the years 2004-2006 were completed in the third quarter of 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 and the year 2008 in February 2008 under its Compliance Assurance Process program. Neither audit is expected to close before December 2008. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.
11. COMMITMENTS, GUARANTEES AND CONTINGENCIES
(A) GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of September 30, 2008, outstanding guarantees and other assurances aggregated approximately $4.2 billion, consisting of parental guarantees - $0.9 billion, subsidiaries’ guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $0.5 billion.
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4 billion (included in the $0.9 billion discussed above) as of September 30, 2008 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of September 30, 2008, FirstEnergy's maximum exposure under these collateral provisions was $573 million, consisting of $64 million due to “material adverse event” contractual clauses and $509 million due to a below investment grade credit rating. Additionally, stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase this amount to $648 million, consisting of $58 million due to “material adverse event” contractual clauses and $590 million due to a below investment grade credit rating.
FES, through potential participation in utility sponsored competitive power procurement processes (including those of affiliates) or through forward hedging transactions and as a consequence of future power price movements, could be required to post significantly higher collateral to support its power transactions.
Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $94 million 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.
In July 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases (see Note 15). The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.
On October 8, 2008, to enhance their liquidity position in the face of the turbulent credit and bond markets, FirstEnergy and its subsidiaries, FES and FGCO entered into a $300 million secured term loan facility with Credit Suisse. Under the facility, FGCO is the borrower and FES and FirstEnergy are guarantors. Generally, the facility is available to FGCO until October 7, 2009, with a minimum borrowing amount of $100 million and maturity 30 days from the date of the borrowing. Once repaid, borrowings may not be re-borrowed.
In early October 2008, FirstEnergy took steps to further enhance its liquidity position by negotiating with the banks that have issued irrevocable direct pay LOCs in support of its outstanding variable interest rate PCRBs to extend the respective reimbursement obligations of the applicable FirstEnergy subsidiary obligors in the event that such LOCs are drawn upon. FirstEnergy’s subsidiaries currently have approximately $2.1 billion variable interest rate PCRBs outstanding (FES - $1.9 billion, OE - $156 million, Met-Ed - $29 million and Penelec - $45 million). The LOCs supporting these PCRBs may be drawn upon to pay the purchase price to bondholders that have exercised the right to tender their PCRBs for mandatory purchase. As a result of these negotiations, a total of approximately $902 million of LOCs that previously required reimbursement within 30 days or less of a draw under the applicable LOC have now been modified to extend the reimbursement obligations to six months or June 2009, as applicable.
| (B) | ENVIRONMENTAL MATTERS |
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on 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. FirstEnergy estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.
FirstEnergy accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance
FirstEnergy is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the 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. FirstEnergy believes it is currently in compliance with this policy, but 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 CAA. FirstEnergy has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.
FirstEnergy complies 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 at 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 facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, is referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above. On September 8, 2008, the Environmental Enforcement Section of the DOJ sent a letter to OE regarding its view that the company was not in compliance with the Sammis NSR Litigation consent decree because the installation of an SNCR at Eastlake Unit 5 was not completed by December 31, 2006. However, the DOJ acknowledged that stipulated penalties could not apply under the terms of the Sammis NSR Litigation consent decree because Eastlake Unit 5 was idled on December 31, 2006 pending installation of the SNCR and advised that it had exercised its discretion not to seek any other penalties for this alleged non-compliance. OE disputed the DOJ's interpretation of the consent decree in a letter dated September 22, 2008. Although the Eastlake Unit 5 issue is no longer active, OE filed a dispute resolution petition on October 23, 2008, with the United States District Court for the Southern District of Ohio, due to potential impacts on its compliance decisions with respect to Burger Units 4 and 5. Under the Sammis NSR Litigation consent decree, an election to repower by December 31, 2012, install flue gas desulfurization (FGD) by December 31, 2010, or permanently shut down those units by December 31, 2010, is due no later than December 31, 2008. Although FirstEnergy will meet the December 31, 2008 deadline for making an election, one potential compliance option, should FGD be elected, would be to idle Burger Units 4 and 5 on December 31, 2010 pending completion of the FGD installation. Thus, OE is seeking a determination by the Court whether this approach is indeed in compliance with the terms of the Sammis NSR Litigation consent decree. The Court has scheduled a hearing on OE’s dispute resolution petition for November 17, 2008. The outcome of this dispute resolution process could have an impact on the option FirstEnergy ultimately elects with respect to Burger Units 4 and 5.
On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.
On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.
On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. By letter dated October 1, 2008, New Jersey informed the Court of its intent to file an amended complaint. Met-Ed is unable to predict the outcome of this matter.
On June 11, 2008, the EPA issued a Notice and Finding of Violation to MEW alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. MEW is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from MEW is disputed. Penelec is unable to predict the outcome of this matter.
On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an ACO modifying that request and setting forth a schedule for FGCO’s response. FGCO complied with the modified schedule and otherwise intends to fully comply with the ACO, but, at this time, is unable to predict the outcome of this matter.
On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.
National Ambient Air Quality Standards
In March 2005, the EPA finalized the 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 non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR would have required 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), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” The Court ruling also vacated the CAIR regional cap and trade requirements for SO2 and NOX, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On October 21, 2008, the Court ordered the parties who appealed CAIR to file responses to the rehearing petitions by November 5, 2008 and directed them to address (1) whether any party is seeking vacatur of CAIR and (2) whether the Court should stay its vacatur of CAIR until EPA promulgates a revised rule. The future cost of compliance with these regulations may be substantial and will depend on the Court’s ruling on rehearing, as well as the action taken by the EPA or Congress in response to the Court’s ruling.
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. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. The Supreme Court could grant the EPA’s petition and alter some or all of the lower Court’s decision, or the EPA could take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.
Climate Change
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, 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.
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environment and Public Works Committee has passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting input from the public on the effects of climate change and the potential ramifications of regulation of CO2 under the CAA.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to 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 FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to 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 life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review one significant aspect of the Second Circuit Court’s opinion which is whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. Oral argument before the Supreme Court is scheduled for December 2, 2008. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs 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 non-hazardous waste.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of September 30, 2008, FirstEnergy had approximately $1.9 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.
The Utilities 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 may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2008, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $94 million (JCP&L - $68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $24 million) have been accrued through September 30, 2008. Included in the total for JCP&L are accrued liabilities of approximately $57 million for environmental remediation of former manufactured gas plants in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
(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 in July 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, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge was held on June 13, 2008. At that conference, the plaintiffs stated their intent to drop their efforts to create a class-wide damage model and, instead of dismissing the class action, expressed their desire for a bifurcated trial on liability and damages. The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario. Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure. JCP&L has received the plaintiffs’ proposed plan of action, and intends to file its objection to the proposed plan, and also file a renewed motion to decertify the class. JCP&L is defending this action but is unable to predict the outcome. No liability has been accrued as of September 30, 2008.
Nuclear Plant Matters
On May 14, 2007, the Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC has conducted the employee training required by the confirmatory order and a consultant has performed follow-up reviews to ensure the effectiveness of that training. The NRC continues to monitor FENOC’s compliance with all the commitments made in the confirmatory order.
In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
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. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint, which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint and oral argument was held on November 5, 2008.
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 arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district Court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. A final order identifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. The Court has yet to render its decision. JCP&L recognized a liability for the potential $16 million award in 2005.
The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties are continuing to bargain with the assistance of a federal mediator. FirstEnergy has a strike mitigation plan ready in the event of a strike.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. 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, results of operations and cash flows.
12. REGULATORY MATTERS
(A) RELIABILITY 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 (the PUCO, the FERC, the NERC and the U.S. – Canada Power System Outage Task Force) regarding enhancements to regional reliability. The proposed enhancements were divided into two groups: enhancements that were to be completed in 2004; and enhancements that were to be completed after 2004. In 2004, FirstEnergy completed all of the enhancements that were recommended for completion in 2004. FirstEnergy is also 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 that could require additional material expenditures.
As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU performed a review of JCP&L’s service reliability. On June 9, 2004, the NJBPU approved a stipulation that addresses a third-party consultant’s recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation incorporates the consultant’s focused audit of, and recommendations regarding, JCP&L’s Planning and Operations and Maintenance programs and practices. On June 1, 2005, the consultant completed his work and issued his final report to the NJBPU. On July 14, 2006, JCP&L filed a comprehensive response to the consultant’s report with the NJBPU. JCP&L will complete the remaining substantive work described in the stipulation in 2008. JCP&L continues to file compliance reports with the NJBPU reflecting JCP&L’s activities associated with implementing the stipulation.
In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Utilities and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.
FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that the NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties and thus have a material adverse effect on its financial condition, results of operations and cash flows.
In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the Midwest ISO region and found it to be in full compliance with all audited reliability standards. Similarly, ReliabilityFirst scheduled a compliance audit of FirstEnergy’s bulk-power system within the PJM region in October 2008. FirstEnergy currently does not expect any material adverse financial impact as a result of these audits.
(B) OHIO
On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007 the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the deferred fuel costs is addressed in the Ohio Companies’ comprehensive ESP filing, as described below. If the recovery of the deferred fuel costs is not resolved in the ESP, or in the event the MRO is implemented, recovery of the deferred fuel costs will be resolved in the proceeding that was instituted with the PUCO on February 8, 2008, as referenced above.
On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings and filing of briefs, the PUCO Staff decreased their recommended revenue increase to a range of $117 million to $135 million. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $58 million of interest costs deferred through September 30, 2008 ($0.12 per share of common stock). The Ohio Companies’ electric distribution rate request is addressed in their comprehensive ESP filing, as described below.
On May 1, 2008, Governor Strickland signed SB221, which became effective on July 31, 2008. The bill requires all utilities to file an ESP with the PUCO. A utility also may file an MRO in which it would have to prove the following objective market criteria:
| · | the utility or its transmission service affiliate belongs to a FERC approved RTO, or there is comparable and nondiscriminatory access to the electric transmission grid; |
| · | the RTO has a market-monitor function and the ability to mitigate market power or the utility’s market conduct, or a similar market monitoring function exists with the ability to identify and monitor market conditions and conduct; and |
| · | a published source of information is available publicly or through subscription that identifies pricing information for traded electricity products, both on- and off-peak, scheduled for delivery two years into the future. |
On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and MRO. The MRO outlines a CBP that would be implemented if the ESP is not approved by the PUCO. Under SB221, a PUCO ruling on the ESP filing is required within 150 days and an MRO decision is required within 90 days. The ESP proposes to phase in new generation rates for customers beginning in 2009 for up to a three-year period and would resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. Major provisions of the ESP include:
| · | a phase-in of new generation rates for up to a three-year period, whereby customers would receive a 10% phase-in credit; related costs (expected to approximate $429 million in 2009, $488 million in 2010 and $553 million in 2011) would be deferred for future collection over a period not to exceed 10 years; |
| · | a reconcilable rider to recover fuel transportation cost surcharges in excess of $30 million in 2009, $20 million in 2010 and $10 million in 2011; |
| · | generation rate adjustments to recover any increase in fuel costs in 2011 over fuel costs incurred in 2010 for FES’ generation assets used to support the ESP; |
| · | generation rate adjustments to recover the costs of complying with new requirements for certain renewable energy resources, new taxes and new environmental laws or new interpretations of existing laws that take effect after January 1, 2008 and exceed $50 million during the plan period; |
| · | an RCP fuel rider to recover the 2006 and 2007 deferred fuel costs and carrying charges (described above) over a period not to exceed 25 years; |
| · | the resolution of outstanding issues pending in the Ohio Companies’ distribution rate case (described above), including annual electric distribution rate increases of $75 million for OE, $34.5 million for CEI and $40.5 million for TE. The new distribution rates would be effective January 1, 2009, for OE and TE and May 1, 2009 for CEI, with a commitment to maintain distribution rates through 2013. CEI also would be authorized to defer $25 million in distribution-related costs incurred from January 1, 2009, through April 30, 2009; |
| · | an adjustable delivery service improvement rider, effective January 1, 2009, through December 31, 2013, to ensure the Ohio Companies maintain and improve customer standards for service and reliability; |
| · | the waiver of RTC charges for CEI’s customers as of January 1, 2009, which would result in CEI’s write-off of approximately $485 million of estimated unrecoverable transition costs ($1.01 per share of common stock); |
| · | the continued recovery of transmission costs, including MISO, ancillary services and congestion charges, through an annually adjusted transmission rider; a separate rider will be established to recover costs incurred annually between May 1st and September 30th for capacity purchases required to meet FERC, NERC, MISO and other applicable standards for planning reserve margin requirements in excess of amounts provided by FES as described in the ESP (the separate application for the recovery of these costs was filed on October 17, 2008); |
| · | a deferred transmission cost recovery rider effective January 1, 2009, through December 31, 2010 to recover transmission costs deferred by the Ohio Companies in 2005 and accumulated carrying charges through December 31, 2008; a deferred distribution cost recovery rider effective January 1, 2011, to recover distribution costs deferred under the RCP, CEI’s additional $25 million of cost deferrals in 2009, line extension deferrals and transition tax deferrals; |
| · | the deferral of annual storm damage expenses in excess of $13.9 million, certain line extension costs, as well as depreciation, property tax obligations and post in-service carrying charges on energy delivery capital investments for reliability and system efficiency placed in service after December 31, 2008. Effective January 1, 2014, a rider will be established to collect the deferred balance and associated carrying charges over a 10-year period; and |
| · | a commitment by the Ohio Companies to invest in aggregate at least $1 billion in capital improvements in their energy delivery systems through 2013 and fund $25 million for energy efficiency programs and $25 million for economic development and job retention programs through 2013. |
Evidentiary hearings in the ESP case concluded on October 31, 2008 and no further hearings are scheduled. The parties are required to submit initial briefs by November 21, 2008, with all reply briefs due by December 12, 2008.
The Ohio Companies’ MRO filing outlines a CBP for providing retail generation supply if the ESP is not approved by the PUCO or is changed and not accepted by the Ohio Companies. The CBP would use a “slice-of-system” approach where suppliers bid on tranches (approximately 100 MW) of the Ohio Companies’ total customer load. If the Ohio Companies proceed with the MRO option, successful bidders (including affiliates) would be required to post independent credit requirements and could be subject to significant collateral calls depending upon power price movement. On September 16, 2008, the PUCO staff filed testimony and evidentiary hearings were held. The PUCO failed to act on October 29, 2008 as required under the statute. The Ohio Companies are unable to predict the outcome of this proceeding.
The Ohio Companies included an interim pricing proposal as part of their ESP filing, if additional time is necessary for final PUCO approval of either the ESP or MRO. FES will be required to obtain FERC authorization to sell electric capacity or energy to the Ohio Companies under the ESP or MRO, unless a waiver is obtained (see FERC Matters).
(C) PENNSYLVANIA
Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. 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 their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.
Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, 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 then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec 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. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.
The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).
On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the Court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. The Commonwealth Court issued its decision on November 7, 2008, which affirmed the PPUC's January 11, 2007 order in all respects, including the deferral and recovery of transmission and congestion related costs.
On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against Met-Ed’s and Penelec’s TSC filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing the company to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted with hearings for both companies scheduled to begin in January 2009. The TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received approval from the PPUC of a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.
On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. As part of the 2008 state budget negotiations, the Alternative Energy Investment Act was enacted creating a $650 million alternative energy fund to increase the development and use of alternative and renewable energy, improve energy efficiency and reduce energy consumption. On October 8, 2008, House Bill 2200 as amended, was voted out of the full Senate and adopted by the House. On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which becomes effective on November 14, 2008 as Act 129 of 2008. The bill addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters and alternative energy. Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009.
Major provisions of the legislation include:
| · | power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a mix of long-term and short-term contracts and spot market purchases; |
| · | the competitive procurement process must be approved by the PPUC and may include auctions, request for proposals, and/or bilateral agreements; |
| · | utilities must provide for the installation of smart meter technology within 15 years; |
| · | a minimum reduction in peak demand of 4.5% by May 31, 2013; |
| · | minimum reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and |
| · | an expanded definition of alternative energy to include additional types of hydroelectric and biomass facilities. |
The current legislative session ends on November 30, 2008, and any pending legislation addressing rate mitigation and the expiration of rate caps not enacted by that time must be re-introduced in order to be considered in the next legislative session which begins in January 2009. While the form and impact of such legislation is uncertain, several legislators and the Governor have indicated their intent to address these issues next year.
On September 25, 2008, Met-Ed and Penelec filed for Commission approval of a Voluntary Prepayment Plan that would provide an opportunity for residential and small commercial customers to pre-pay an amount, which would earn interest at 7.5%, on their monthly electric bills in 2009 and 2010, to be used to reduce electric rates in 2011 and 2012. Met-Ed and Penelec also intend to file a generation procurement plan for 2011 and beyond with the PPUC later this year or early next year. Met-Ed and Penelec requested that the PPUC approve the Plan by mid-December 2008 and are currently awaiting a decision.
(D) 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 September 30, 2008, the accumulated deferred cost balance totaled approximately $210 million.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting 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. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU 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 the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that 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. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional 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. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 and comments from interested parties were submitted by May 19, 2008.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the first half of 2008.
On April 17, 2008, a draft EMP was released for public comment. The final EMP was issued on October 22, 2008 and establishes five major goals:
| · | maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020; |
| · | reduce peak demand for electricity by 5,700 MW by 2020; |
| · | meet 30% of the state’s electricity needs with renewable energy by 2020; |
| · | examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and |
| · | invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey. |
The final EMP will be followed by appropriate legislation and regulation as necessary. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations or those of JCP&L.
(E) FERC MATTERS
Transmission Service between MISO and PJM
On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC by year-end 2008. In the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision.
PJM Transmission Rate Design
On January 31, 2005, certain PJM transmission owners made 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. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce the costs of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions are due on November 10, 2008. On February 11, 2008, AEP appealed the FERC’s April 19, 2007 and January 31, 2008 orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.
Post Transition Period Rate Design
The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.
On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP is pending before the FERC.
MISO Ancillary Services Market and Balancing Area Consolidation
MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. These markets would permit generators to sell, and load-serving entities to purchase, their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. Numerous parties filed requests for rehearing on March 26, 2008. On June 23, 2008, the FERC issued an order granting in part and denying in part rehearing.
On February 29, 2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor ASM and Consolidated Balancing Authority Initiative Verification plan and status and Real-Time Operations ASM Reversion plan. FERC action on this compliance filing remains pending. On March 26, 2008, MISO submitted a tariff filing in compliance with the FERC’s 30-day directives in the February 25 order. Numerous parties submitted comments and protests on April 16, 2008. The FERC issued an order accepting the revisions pending further compliance on June 23, 2008. On April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s 60-day directives in the February 25 order. FERC action on this compliance filing remains pending. On May 23, 2008, MISO submitted its amended Balancing Authority Agreement. On July 21, 2008, the FERC issued an order conditionally accepting the amended Balancing Authority Agreement and requiring a further compliance filing. On August 19, 2008, MISO submitted its compliance filing to the FERC. On July 25, 2008, MISO submitted another Readiness Certification. The FERC has not yet acted on this submission. MISO announced on August 26, 2008 that the startup of its market is postponed indefinitely. MISO commits to make a filing giving at least sixty days notice of the new effective date. The latest announced effective date for market startup is January 6, 2009.
Interconnection Agreement with AMP-Ohio
On May 29, 2008, TE filed with the FERC a proposed Notice of Cancellation effective midnight December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio protested this filing. TE also filed a Petition for Declaratory Order seeking a FERC ruling, in the alternative if cancellation is not accepted, of TE's right to file for an increase in rates effective January 1, 2009, for power provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a pleading agreeing that TE may seek an increase in rates, but arguing that any increase is limited to the cost of generation owned by TE affiliates. On August 18, 2008, the FERC issued an order that suspended the cancellation of the Agreement for five months, to become effective on June 1, 2009, and established expedited hearing procedures on issues raised in the filing and TE’s Petition for Declaratory Order. On October 14, 2008, the parties filed a settlement agreement and mutual notice of cancellation of the Interconnection Agreement effective midnight December 31, 2008. Upon acceptance by the FERC, this filing will terminate the litigation and the Interconnection Agreement, among other effects.
Duquesne’s Request to Withdraw from PJM
On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne zone load-serving entities to pay their PJM capacity obligations through May 31, 2011.
FirstEnergy desires to continue to use its Duquesne zone generation resources to serve load in PJM. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification on whether Duquesne-zone generators could participate in PJM’s May 2008 auction for the 2011-2012 planning year. In the order, the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators could contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with the FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction.
The FERC also directed MISO and PJM to resolve the substantive and procedural issues associated with Duquesne’s transition into MISO. As directed, PJM filed thirteen load-serving entity Capacity Payment Agreements and a Capacity Portability Agreement with the FERC. The Capacity Payment Agreements addressed Duquesne Zone load-serving entity obligations through May 31, 2011 with regards to RPM Capacity while the Capacity Portability Agreement addressed operational issues associated with the portability of such capacity. On September 30, 2008, the FERC approved both agreements, subject to conditions, taking notice of many operational and procedural issues brought forth by FirstEnergy and other market participants.
Several issues surrounding Duquesne’s transition into MISO continue to be contested at the FERC. Specifically, Duquesne’s obligation to pay for transmission expansion costs allocated to the Duquesne zone when they were a member of PJM, and other issues in which market participants wish to be held harmless by Duquesne’s transition. FirstEnergy filed for rehearing on these issues on October 3, 2008. Duquesne’s transition into MISO is also contingent upon the start of MISO’s ancillary services market and consolidation of its balancing authorities, currently scheduled for January 6, 2009.
Complaint against PJM RPM Auction
On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by the FERC that established the RPM. In the complaint, the RPM Buyers request that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On July 11, 2008, PJM filed its answer to the complaint, in which it denied the allegation that the rates are unjust and unreasonable. Also on that date, FirstEnergy filed a motion to intervene.
On September 19, 2008, the FERC denied the RPM Buyers complaint. However, the FERC did grant the RPM Buyers request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on its progress on contemplating adjustments to the RPM as suggested by the Brattle Group in its report reviewing the RPM. The technical conference will take place in February, 2009. On October 20, 2008, the RPM Buyers filed a request for rehearing of the FERC’s September 19, 2008 order.
MISO Resource Adequacy Proposal
MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load-serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load-serving entities in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing. On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchase power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. Issuance of these orders is not expected to delay the June 1, 2009 start date for MISO Resource Adequacy.
Organized Wholesale Power Markets
The FERC issued a final rule on October 17, 2008, amending its regulations to “improve the operation of organized wholesale electric markets in the areas of: (1) demand response and market pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market-monitoring policies; and (4) the responsiveness of RTOs and ISOs to their customers and other stakeholders.” The RTOs and ISOs were directed to submit amendments to their respective tariffs to address these market operation improvements. The final rule directs RTOs to adopt market rules permitting prices to increase during periods of supply shortages and to permit enhanced participation by demand response resources. It also codifies and defines for the first time the roles and duties of independent market monitors within RTOs. Finally, it adopts requirements for enhanced access by stakeholders to RTO boards of directors. RTOs are directed to make compliance filings six months from the effective date of the final rule. The final rule is not expected to have any material effect on FirstEnergy's operations within MISO and PJM.
FES Sales to Affiliates
On October 24, 2008, FES, on its own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies in January 2009 pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. A ruling by the FERC is expected the week of December 15, 2008.
On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and The Waverly Power and Light Company (Waverly) effective November 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be supplied by FES in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the default or failure of supply of their committed resources. Prices for the power provided by FES were not changed in the Third Restated Partial Requirements Agreement.
13. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
SFAS 141(R) – “Business Combinations”
In December 2007, the FASB issued SFAS 141(R), which: (i) requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction; (ii) establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and (iii) requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in deferred tax valuation allowances and income tax uncertainties made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. Under SFAS 141(R), adjustments to the acquired entity’s deferred tax assets and uncertain tax position balances occurring outside the measurement period will be recorded as a component of income tax expense, rather than goodwill. The impact of FirstEnergy’s application of this Standard in periods after implementation will be dependent upon acquisitions at that time.
SFAS 160 - “Non-controlling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”
In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FirstEnergy’s financial statements.
| | SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” |
In March 2008, the FASB issued SFAS 161 that enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. The FASB believes that additional required disclosure of the fair values of derivative instruments and their gains and losses in a tabular format will provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. This Statement also requires cross-referencing within the footnotes to help users of financial statements locate important information about derivative instruments. The Statement is effective for reporting periods beginning after November 15, 2008. FirstEnergy expects this Standard to increase its disclosure requirements for derivative instruments and hedging activities.
14. SEGMENT INFORMATION
FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The assets and revenues for all other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”
The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. Its revenues are primarily derived from the delivery of electricity, cost recovery of regulatory assets, and default service electric generation sales to non-shopping customers in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under partial requirements purchased power agreements and from non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.
The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive electricity sales primarily in Ohio, Pennsylvania, Maryland and Michigan, owns or leases and operates FirstEnergy’s generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from the affiliated company PSA sales and the non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment’s customers. The segment’s internal revenues represent the affiliated company PSA sales.
The Ohio transitional generation services segment represents the regulated generation commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect the purchase of electricity from the competitive energy services segment through full-requirements PSA arrangements, the deferral and amortization of certain fuel costs authorized for recovery by the energy delivery services segment and the net MISO transmission revenues and expenses related to the delivery of generation load. This segment’s total assets consist of accounts receivable for generation revenues from retail customers.
| Segment Financial Information | | | | | | | | | | | | | | | | |
| | | | | | | | | Ohio | | | | | | | | | | |
| | | Energy | | | Competitive | | | Transitional | | | | | | | | | | |
| | | Delivery | | | Energy | | | Generation | | | | | | Reconciling | | | | |
| Three Months Ended | | Services | | | Services | | | Services | | | Other | | | Adjustments | | | Consolidated | |
| | | (In millions) | |
| September 30, 2008 | | | | | | | | | | | | | | | | | | |
| External revenues | | $ | 2,657 | | | $ | 460 | | | $ | 813 | | | $ | 5 | | | $ | (31 | ) | | $ | 3,904 | |
| Internal revenues | | | - | | | | 786 | | | | - | | | | - | | | | (786 | ) | | | - | |
| Total revenues | | | 2,657 | | | | 1,246 | | | | 813 | | | | 5 | | | | (817 | ) | | | 3,904 | |
| Depreciation and amortization | | | 286 | | | | 67 | | | | 46 | | | | 1 | | | | 1 | | | | 401 | |
| Investment income | | | 48 | | | | 13 | | | | 1 | | | | - | | | | (22 | ) | | | 40 | |
| Net interest charges | | | 101 | | | | 31 | | | | 1 | | | | - | | | | 44 | | | | 177 | |
| Income taxes | | | 188 | | | | 109 | | | | 14 | | | | (46 | ) | | | (27 | ) | | | 238 | |
| Net income | | | 283 | | | | 164 | | | | 19 | | | | 48 | | | | (43 | ) | | | 471 | |
| Total assets | | | 23,088 | | | | 9,360 | | | | 270 | | | | 457 | | | | 387 | | | | 33,562 | |
| Total goodwill | | | 5,559 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,583 | |
| Property additions | | | 170 | | | | 285 | | | | - | | | | 85 | | | | 20 | | | | 560 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2007 | | | | | | | | | | | | | | | | | | | | | | | | |
| External revenues | | $ | 2,520 | | | $ | 370 | | | $ | 723 | | | $ | 9 | | | $ | 19 | | | $ | 3,641 | |
| Internal revenues | | | - | | | | 806 | | | | - | | | | - | | | | (806 | ) | | | - | |
| Total revenues | | | 2,520 | | | | 1,176 | | | | 723 | | | | 9 | | | | (787 | ) | | | 3,641 | |
| Depreciation and amortization | | | 299 | | | | 51 | | | | (16 | ) | | | 1 | | | | 8 | | | | 343 | |
| Investment income | | | 58 | | | | 5 | | | | - | | | | 1 | | | | (34 | ) | | | 30 | |
| Net interest charges | | | 117 | | | | 39 | | | | - | | | | 1 | | | | 37 | | | | 194 | |
| Income taxes | | | 175 | | | | 99 | | | | 11 | | | | (2 | ) | | | (10 | ) | | | 273 | |
| Net income | | | 269 | | | | 148 | | | | 16 | | | | 6 | | | | (26 | ) | | | 413 | |
| Total assets | | | 23,308 | | | | 7,182 | | | | 268 | | | | 232 | | | | 663 | | | | 31,653 | |
| Total goodwill | | | 5,585 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,609 | |
| Property additions | | | 209 | | | | 199 | | | | - | | | | 3 | | | | 19 | | | | 430 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2008 | | | | | | | | | | | | | | | | | | | | | | | | |
| External revenues | | $ | 7,051 | | | $ | 1,164 | | | $ | 2,203 | | | $ | 65 | | | $ | (57 | ) | | $ | 10,426 | |
| Internal revenues | | | - | | | | 2,266 | | | | - | | | | - | | | | (2,266 | ) | | | - | |
| Total revenues | | | 7,051 | | | | 3,430 | | | | 2,203 | | | | 65 | | | | (2,323 | ) | | | 10,426 | |
| Depreciation and amortization | | | 782 | | | | 179 | | | | 61 | | | | 2 | | | | 10 | | | | 1,034 | |
| Investment income | | | 133 | | | | (1 | ) | | | 1 | | | | 6 | | | | (66 | ) | | | 73 | |
| Net interest charges | | | 303 | | | | 86 | | | | 1 | | | | - | | | | 133 | | | | 523 | |
| Income taxes | | | 436 | | | | 212 | | | | 42 | | | | (33 | ) | | | (72 | ) | | | 585 | |
| Net income | | | 655 | | | | 317 | | | | 62 | | | | 96 | | | | (120 | ) | | | 1,010 | |
| Total assets | | | 23,088 | | | | 9,360 | | | | 270 | | | | 457 | | | | 387 | | | | 33,562 | |
| Total goodwill | | | 5,559 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,583 | |
| Property additions | | | 621 | | | | 1,430 | | | | - | | | | 106 | | | | 20 | | | | 2,177 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2007 | | | | | | | | | | | | | | | | | | | | | | | | |
| External revenues | | $ | 6,655 | | | $ | 1,089 | | | $ | 1,968 | | | $ | 29 | | | $ | (18 | ) | | $ | 9,723 | |
| Internal revenues | | | - | | | | 2,210 | | | | - | | | | - | | | | (2,210 | ) | | | - | |
| Total revenues | | | 6,655 | | | | 3,299 | | | | 1,968 | | | | 29 | | | | (2,228 | ) | | | 9,723 | |
| Depreciation and amortization | | | 767 | | | | 153 | | | | (80 | ) | | | 3 | | | | 20 | | | | 863 | |
| Investment income | | | 190 | | | | 13 | | | | 1 | | | | 1 | | | | (112 | ) | | | 93 | |
| Net interest charges | | | 340 | | | | 131 | | | | 1 | | | | 3 | | | | 97 | | | | 572 | |
| Income taxes | | | 464 | | | | 259 | | | | 46 | | | | - | | | | (74 | ) | | | 695 | |
| Net income | | | 695 | | | | 388 | | | | 69 | | | | 13 | | | | (124 | ) | | | 1,041 | |
| Total assets | | | 23,308 | | | | 7,182 | | | | 268 | | | | 232 | | | | 663 | | | | 31,653 | |
| Total goodwill | | | 5,585 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,609 | |
| Property additions | | | 609 | | | | 462 | | | | - | | | | 6 | | | | 50 | | | | 1,127 | |
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 and elimination of intersegment transactions.
15. SUPPLEMENTAL GUARANTOR INFORMATION
On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty. This transaction is classified as an operating lease under GAAP for FES and FirstEnergy and a financing for FGCO.
The consolidating statements of income for the three-month and nine-month periods ended September 30, 2008 and 2007, consolidating balance sheets as of September 30, 2008 and December 31, 2007 and condensed consolidating statements of cash flows for the nine months ended September 30, 2008 and 2007 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONSOLIDATING STATEMENTS OF INCOME | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
For the Three Months Ended September 30, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| REVENUES | | $ | 1,222,783 | | | $ | 574,394 | | | $ | 267,017 | | | $ | (822,590 | ) | | $ | 1,241,604 | |
| | | | | | | | | | | | | | | | | | | | | |
| EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 8,177 | | | | 307,646 | | | | 34,123 | | | | - | | | | 349,946 | |
| Purchased power from non-affiliates | | | 221,493 | | | | - | | | | - | | | | - | | | | 221,493 | |
| Purchased power from affiliates | | | 815,243 | | | | 7,347 | | | | 15,821 | | | | (822,590 | ) | | | 15,821 | |
| Other operating expenses | | | 35,596 | | | | 110,701 | | | | 120,697 | | | | 12,190 | | | | 279,184 | |
| Provision for depreciation | | | 1,978 | | | | 33,432 | | | | 30,559 | | | | (1,336 | ) | | | 64,633 | |
| General taxes | | | 4,829 | | | | 10,768 | | | | 6,139 | | | | - | | | | 21,736 | |
| Total expenses | | | 1,087,316 | | | | 469,894 | | | | 207,339 | | | | (811,736 | ) | | | 952,813 | |
| | | | - | | | | - | | | | - | | | | - | | | | | |
| OPERATING INCOME | | | 135,467 | | | | 104,500 | | | | 59,678 | | | | (10,854 | ) | | | 288,791 | |
| | | | | | | | | | | | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | | | | |
| net income from equity investees | | | 102,777 | | | | (515 | ) | | | 13,287 | | | | (97,122 | ) | | | 18,427 | |
| Interest expense - affiliates | | | (120 | ) | | | (4,963 | ) | | | (2,932 | ) | | | - | | | | (8,015 | ) |
| Interest expense - other | | | (8,464 | ) | | | (23,447 | ) | | | (17,183 | ) | | | 16,325 | | | | (32,769 | ) |
| Capitalized interest | | | 41 | | | | 11,376 | | | | 978 | | | | - | | | | 12,395 | |
| Total other income (expense) | | | 94,234 | | | | (17,549 | ) | | | (5,850 | ) | | | (80,797 | ) | | | (9,962 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 229,701 | | | | 86,951 | | | | 53,828 | | | | (91,651 | ) | | | 278,829 | |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME TAXES | | | 44,046 | | | | 31,863 | | | | 14,995 | | | | 2,270 | | | | 93,174 | |
| | | | | | | | | | | | | | | | | | | | | |
| NET INCOME | | $ | 185,655 | | | $ | 55,088 | | | $ | 38,833 | | | $ | (93,921 | ) | | $ | 185,655 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONSOLIDATING STATEMENTS OF INCOME | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Three Months Ended September 30, 2007 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| REVENUES | | $ | 1,180,449 | | | $ | 496,204 | | | $ | 280,072 | | | $ | (785,817 | ) | | $ | 1,170,908 | |
| | | | | | | | | | | | | | | | | | | | | |
| EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 10,944 | | | | 261,759 | | | | 29,083 | | | | - | | | | 301,786 | |
| Purchased power from non-affiliates | | | 228,755 | | | | - | | | | - | | | | - | | | | 228,755 | |
| Purchased power from affiliates | | | 774,873 | | | | 57,927 | | | | 15,525 | | | | (785,817 | ) | | | 62,508 | |
| Other operating expenses | | | 41,828 | | | | 75,985 | | | | 117,220 | | | | - | | | | 235,033 | |
| Provision for depreciation | | | 650 | | | | 24,669 | | | | 23,181 | | | | - | | | | 48,500 | |
| General taxes | | | 5,406 | | | | 11,788 | | | | 5,048 | | | | - | | | | 22,242 | |
| Total expenses | | | 1,062,456 | | | | 432,128 | | | | 190,057 | | | | (785,817 | ) | | | 898,824 | |
| | | | | | | | | | | | | | | | | | | | | |
| OPERATING INCOME | | | 117,993 | | | | 64,076 | | | | 90,015 | | | | - | | | | 272,084 | |
| | | | | | | | | | | | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Miscellaneous income, including | | | | | | | | | | | | | | | | | | | | |
| net income from equity investees | | | 82,870 | | | | 2,375 | | | | 3,935 | | | | (76,525 | ) | | | 12,655 | |
| Interest expense - affiliates | | | (676 | ) | | | (4,769 | ) | | | (4,196 | ) | | | - | | | | (9,641 | ) |
| Interest expense - other | | | (808 | ) | | | (21,274 | ) | | | (9,712 | ) | | | - | | | | (31,794 | ) |
| Capitalized interest | | | 9 | | | | 3,889 | | | | 1,233 | | | | - | | | | 5,131 | |
| Total other income (expense) | | | 81,395 | | | | (19,779 | ) | | | (8,740 | ) | | | (76,525 | ) | | | (23,649 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 199,388 | | | | 44,297 | | | | 81,275 | | | | (76,525 | ) | | | 248,435 | |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME TAXES | | | 44,624 | | | | 19,850 | | | | 29,197 | | | | - | | | | 93,671 | |
| | | | | | | | | | | | | | | | | | | | | |
| NET INCOME | | $ | 154,764 | | | $ | 24,447 | | | $ | 52,078 | | | $ | (76,525 | ) | | $ | 154,764 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONSOLIDATING STATEMENTS OF INCOME | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Nine Months Ended September 30, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| REVENUES | | $ | 3,387,258 | | | $ | 1,707,320 | | | $ | 879,729 | | | $ | (2,562,309 | ) | | $ | 3,411,998 | |
| | | | | | | | | | | | | | | | | | | | | |
| EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 13,920 | | | | 876,077 | | | | 92,188 | | | | - | | | | 982,185 | |
| Purchased power from non-affiliates | | | 648,556 | | | | - | | | | - | | | | - | | | | 648,556 | |
| Purchased power from affiliates | | | 2,549,892 | | | | 12,417 | | | | 75,834 | | | | (2,562,309 | ) | | | 75,834 | |
| Other operating expenses | | | 103,034 | | | | 342,041 | | | | 381,826 | | | | 36,567 | | | | 863,468 | |
| Provision for depreciation | | | 3,885 | | | | 90,058 | | | | 80,646 | | | | (4,054 | ) | | | 170,535 | |
| General taxes | | | 14,971 | | | | 33,842 | | | | 15,915 | | | | - | | | | 64,728 | |
| Total expenses | | | 3,334,258 | | | | 1,354,435 | | | | 646,409 | | | | (2,529,796 | ) | | | 2,805,306 | |
| | | | | | | | | | | | | | | | | | | | | |
| OPERATING INCOME | | | 53,000 | | | | 352,885 | | | | 233,320 | | | | (32,513 | ) | | | 606,692 | |
| | | | | | | | | | | | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | | | | |
| net income from equity investees | | | 323,092 | | | | (1,234 | ) | | | (2,699 | ) | | | (305,710 | ) | | | 13,449 | |
| Interest expense - affiliates | | | (252 | ) | | | (18,172 | ) | | | (7,529 | ) | | | - | | | | (25,953 | ) |
| Interest expense - other | | | (19,105 | ) | | | (73,112 | ) | | | (38,833 | ) | | | 49,241 | | | | (81,809 | ) |
| Capitalized interest | | | 90 | | | | 27,460 | | | | 2,049 | | | | - | | | | 29,599 | |
| Total other income (expense) | | | 303,825 | | | | (65,058 | ) | | | (47,012 | ) | | | (256,469 | ) | | | (64,714 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 356,825 | | | | 287,827 | | | | 186,308 | | | | (288,982 | ) | | | 541,978 | |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME TAXES | | | 13,092 | | | | 109,615 | | | | 68,597 | | | | 6,941 | | | | 198,245 | |
| | | | | | | | | | | | | | | | | | | | | |
| NET INCOME | | $ | 343,733 | | | $ | 178,212 | | | $ | 117,711 | | | $ | (295,923 | ) | | $ | 343,733 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONSOLIDATING STATEMENTS OF INCOME | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
For the Nine Months Ended September 30, 2007 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| REVENUES | | $ | 3,274,694 | | | $ | 1,501,112 | | | $ | 793,255 | | | $ | (2,311,129 | ) | | $ | 3,257,932 | |
| | | | | | | | | | | | | | | | | | | | | |
| EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 20,824 | | | | 698,643 | | | | 84,734 | | | | - | | | | 804,201 | |
| Purchased power from non-affiliates | | | 577,831 | | | | - | | | | - | | | | - | | | | 577,831 | |
| Purchased power from affiliates | | | 2,290,305 | | | | 176,654 | | | | 53,746 | | | | (2,311,129 | ) | | | 209,576 | |
| Other operating expenses | | | 123,596 | | | | 240,774 | | | | 367,404 | | | | - | | | | 731,774 | |
| Provision for depreciation | | | 1,572 | | | | 74,844 | | | | 68,614 | | | | - | | | | 145,030 | |
| General taxes | | | 15,942 | | | | 31,406 | | | | 17,522 | | | | - | | | | 64,870 | |
| Total expenses | | | 3,030,070 | | | | 1,222,321 | | | | 592,020 | | | | (2,311,129 | ) | | | 2,533,282 | |
| | | | | | | | | | | | | | | | | | | | | |
| OPERATING INCOME | | | 244,624 | | | | 278,791 | | | | 201,235 | | | | - | | | | 724,650 | |
| | | | | | | | | | | | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Miscellaneous income, including | | | | | | | | | | | | | | | | | | | | |
| net income from equity investees | | | 271,599 | | | | 2,669 | | | | 13,350 | | | | (239,862 | ) | | | 47,756 | |
| Interest expense - affiliates | | | (676 | ) | | | (47,090 | ) | | | (14,138 | ) | | | - | | | | (61,904 | ) |
| Interest expense - other | | | (7,966 | ) | | | (34,150 | ) | | | (28,729 | ) | | | - | | | | (70,845 | ) |
| Capitalized interest | | | 20 | | | | 9,044 | | | | 3,699 | | | | - | | | | 12,763 | |
| Total other income (expense) | | | 262,977 | | | | (69,527 | ) | | | (25,818 | ) | | | (239,862 | ) | | | (72,230 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 507,601 | | | | 209,264 | | | | 175,417 | | | | (239,862 | ) | | | 652,420 | |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME TAXES | | | 98,917 | | | | 82,031 | | | | 62,788 | | | | - | | | | 243,736 | |
| | | | | | | | | | | | | | | | | | | | | |
| NET INCOME | | $ | 408,684 | | | $ | 127,233 | | | $ | 112,629 | | | $ | (239,862 | ) | | $ | 408,684 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONSOLIDATING BALANCE SHEETS | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| As of September 30, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| ASSETS | | | | | | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
| Receivables- | | | | | | | | | | | | | | | | | | | | |
| Customers | | | 137,126 | | | | - | | | | - | | | | - | | | | 137,126 | |
| Associated companies | | | 267,777 | | | | 195,005 | | | | 100,481 | | | | (299,484 | ) | | | 263,779 | |
| Other | | | 910 | | | | 1,595 | | | | 20,419 | | | | - | | | | 22,924 | |
| Notes receivable from associated companies | | | 118,526 | | | | 38,400 | | | | - | | | | - | | | | 156,926 | |
| Materials and supplies, at average cost | | | 3,519 | | | | 288,623 | | | | 205,134 | | | | - | | | | 497,276 | |
| Prepayments and other | | | 64,585 | | | | 84,138 | | | | 30,807 | | | | - | | | | 179,530 | |
| | | | 592,445 | | | | 607,761 | | | | 356,841 | | | | (299,484 | ) | | | 1,257,563 | |
| | | | | | | | | | | | | | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
| In service | | | 108,733 | | | | 5,413,310 | | | | 4,704,478 | | | | (391,859 | ) | | | 9,834,662 | |
| Less - Accumulated provision for depreciation | | | 10,990 | | | | 2,712,638 | | | | 1,658,863 | | | | (170,774 | ) | | | 4,211,717 | |
| | | | 97,743 | | | | 2,700,672 | | | | 3,045,615 | | | | (221,085 | ) | | | 5,622,945 | |
| Construction work in progress | | | 2,827 | | | | 1,225,381 | | | | 157,444 | | | | - | | | | 1,385,652 | |
| | | | 100,570 | | | | 3,926,053 | | | | 3,203,059 | | | | (221,085 | ) | | | 7,008,597 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,145,384 | | | | - | | | | 1,145,384 | |
| Long-term notes receivable from associated companies | | | - | | | | - | | | | 62,900 | | | | - | | | | 62,900 | |
| Investment in associated companies | | | 3,581,979 | | | | - | | | | - | | | | (3,581,979 | ) | | | - | |
| Other | | | 2,124 | | | | 38,247 | | | | 202 | | | | - | | | | 40,573 | |
| | | | 3,584,103 | | | | 38,247 | | | | 1,208,486 | | | | (3,581,979 | ) | | | 1,248,857 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income taxes | | | 9,655 | | | | 471,718 | | | | - | | | | (251,032 | ) | | | 230,341 | |
| Lease assignment receivable from associated companies | | | - | | | | 71,356 | | | | - | | | | - | | | | 71,356 | |
| Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | |
| Property taxes | | | - | | | | 25,007 | | | | 22,767 | | | | - | | | | 47,774 | |
| Pension assets | | | 3,208 | | | | 11,556 | | | | - | | | | - | | | | 14,764 | |
| Unamortized sale and leaseback costs | | | - | | | | 8,445 | | | | - | | | | 48,920 | | | | 57,365 | |
| Other | | | 18,343 | | | | 59,511 | | | | 18,717 | | | | (46,869 | ) | | | 49,702 | |
| | | | 55,454 | | | | 647,593 | | | | 41,484 | | | | (248,981 | ) | | | 495,550 | |
| | | $ | 4,332,572 | | | $ | 5,219,654 | | | $ | 4,809,870 | | | $ | (4,351,529 | ) | | $ | 10,010,567 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Currently payable long-term debt | | $ | 4,679 | | | $ | 873,562 | | | $ | 1,077,289 | | | $ | (17,315 | ) | | $ | 1,938,215 | |
| Short-term borrowings- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | - | | | | 147,108 | | | | 164,642 | | | | - | | | | 311,750 | |
| Other | | | 1,000,000 | | | | - | | | | - | | | | - | | | | 1,000,000 | |
| Accounts payable- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 276,155 | | | | 202,678 | | | | 158,215 | | | | (275,601 | ) | | | 361,447 | |
| Other | | | 36,724 | | | | 126,449 | | | | - | | | | - | | | | 163,173 | |
| Accrued taxes | | | 4,109 | | | | 88,826 | | | | 17,661 | | | | (29,877 | ) | | | 80,719 | |
| Other | | | 36,491 | | | | 116,637 | | | | 26,777 | | | | 38,009 | | | | 217,914 | |
| | | | 1,358,158 | | | | 1,555,260 | | | | 1,444,584 | | | | (284,784 | ) | | | 4,073,218 | |
| CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
| Common stockholder's equity | | | 2,916,934 | | | | 1,813,911 | | | | 1,755,054 | | | | (3,568,965 | ) | | | 2,916,934 | |
| Long-term debt and other long-term obligations | | | 40,333 | | | | 1,364,207 | | | | 451,365 | | | | (1,296,982 | ) | | | 558,923 | |
| | | | 2,957,267 | | | | 3,178,118 | | | | 2,206,419 | | | | (4,865,947 | ) | | | 3,475,857 | |
| NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,035,013 | | | | 1,035,013 | |
| Accumulated deferred income taxes | | | - | | | | - | | | | 235,811 | | | | (235,811 | ) | | | - | |
| Accumulated deferred investment tax credits | | | - | | | | 40,209 | | | | 23,759 | | | | - | | | | 63,968 | |
| Asset retirement obligations | | | - | | | | 24,148 | | | | 825,327 | | | | - | | | | 849,475 | |
| Retirement benefits | | | 9,745 | | | | 57,822 | | | | - | | | | - | | | | 67,567 | |
| Property taxes | | | - | | | | 25,328 | | | | 22,767 | | | | - | | | | 48,095 | |
| Lease market valuation liability | | | - | | | | 319,129 | | | | - | | | | - | | | | 319,129 | |
| Other | | | 7,402 | | | | 19,640 | | | | 51,203 | | | | - | | | | 78,245 | |
| | | | 17,147 | | | | 486,276 | | | | 1,158,867 | | | | 799,202 | | | | 2,461,492 | |
| | | $ | 4,332,572 | | | $ | 5,219,654 | | | $ | 4,809,870 | | | $ | (4,351,529 | ) | | $ | 10,010,567 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONSOLIDATING BALANCE SHEETS | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| As of December 31, 2007 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| ASSETS | | | | | | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
| Receivables- | | | | | | | | | | | | | | | | | | | | |
| Customers | | | 133,846 | | | | - | | | | - | | | | - | | | | 133,846 | |
| Associated companies | | | 327,715 | | | | 237,202 | | | | 98,238 | | | | (286,656 | ) | | | 376,499 | |
| Other | | | 2,845 | | | | 978 | | | | - | | | | - | | | | 3,823 | |
| Notes receivable from associated companies | | | 23,772 | | | | - | | | | 69,012 | | | | - | | | | 92,784 | |
| Materials and supplies, at average cost | | | 195 | | | | 215,986 | | | | 210,834 | | | | - | | | | 427,015 | |
| Prepayments and other | | | 67,981 | | | | 21,605 | | | | 2,754 | | | | - | | | | 92,340 | |
| | | | 556,356 | | | | 475,771 | | | | 380,838 | | | | (286,656 | ) | | | 1,126,309 | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
| In service | | | 25,513 | | | | 5,065,373 | | | | 3,595,964 | | | | (392,082 | ) | | | 8,294,768 | |
| Less - Accumulated provision for depreciation | | | 7,503 | | | | 2,553,554 | | | | 1,497,712 | | | | (166,756 | ) | | | 3,892,013 | |
| | | | 18,010 | | | | 2,511,819 | | | | 2,098,252 | | | | (225,326 | ) | | | 4,402,755 | |
| Construction work in progress | | | 1,176 | | | | 571,672 | | | | 188,853 | | | | - | | | | 761,701 | |
| | | | 19,186 | | | | 3,083,491 | | | | 2,287,105 | | | | (225,326 | ) | | | 5,164,456 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,332,913 | | | | - | | | | 1,332,913 | |
| Long-term notes receivable from associated companies | | | - | | | | - | | | | 62,900 | | | | - | | | | 62,900 | |
| Investment in associated companies | | | 2,516,838 | | | | - | | | | - | | | | (2,516,838 | ) | | | - | |
| Other | | | 2,732 | | | | 37,071 | | | | 201 | | | | - | | | | 40,004 | |
| | | | 2,519,570 | | | | 37,071 | | | | 1,396,014 | | | | (2,516,838 | ) | | | 1,435,817 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income taxes | | | 16,978 | | | | 522,216 | | | | - | | | | (262,271 | ) | | | 276,923 | |
| Lease assignment receivable from associated companies | | | - | | | | 215,258 | | | | - | | | | - | | | | 215,258 | |
| Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | |
| Property taxes | | | - | | | | 25,007 | | | | 22,767 | | | | - | | | | 47,774 | |
| Pension asset | | | 3,217 | | | | 13,506 | | | | - | | | | - | | | | 16,723 | |
| Unamortized sale and leaseback costs | | | - | | | | 27,597 | | | | - | | | | 43,206 | | | | 70,803 | |
| Other | | | 22,956 | | | | 52,971 | | | | 6,159 | | | | (38,133 | ) | | | 43,953 | |
| | | | 67,399 | | | | 856,555 | | | | 28,926 | | | | (257,198 | ) | | | 695,682 | |
| | | $ | 3,162,511 | | | $ | 4,452,888 | | | $ | 4,092,883 | | | $ | (3,286,018 | ) | | $ | 8,422,264 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Currently payable long-term debt | | $ | - | | | $ | 596,827 | | | $ | 861,265 | | | $ | (16,896 | ) | | $ | 1,441,196 | |
| Short-term borrowings- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | - | | | | 238,786 | | | | 25,278 | | | | - | | | | 264,064 | |
| Other | | | 300,000 | | | | - | | | | - | | | | - | | | | 300,000 | |
| Accounts payable- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 287,029 | | | | 175,965 | | | | 268,926 | | | | (286,656 | ) | | | 445,264 | |
| Other | | | 56,194 | | | | 120,927 | | | | - | | | | - | | | | 177,121 | |
| Accrued taxes | | | 18,831 | | | | 125,227 | | | | 28,229 | | | | (836 | ) | | | 171,451 | |
| Other | | | 57,705 | | | | 131,404 | | | | 11,972 | | | | 36,725 | | | | 237,806 | |
| | | | 719,759 | | | | 1,389,136 | | | | 1,195,670 | | | | (267,663 | ) | | | 3,036,902 | |
| CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
| Common stockholder's equity | | | 2,414,231 | | | | 951,542 | | | | 1,562,069 | | | | (2,513,611 | ) | | | 2,414,231 | |
| Long-term debt and other long-term obligations | | | - | | | | 1,597,028 | | | | 242,400 | | | | (1,305,716 | ) | | | 533,712 | |
| | | | 2,414,231 | | | | 2,548,570 | | | | 1,804,469 | | | | (3,819,327 | ) | | | 2,947,943 | |
| NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,060,119 | | | | 1,060,119 | |
| Accumulated deferred income taxes | | | - | | | | - | | | | 259,147 | | | | (259,147 | ) | | | - | |
| Accumulated deferred investment tax credits | | | - | | | | 36,054 | | | | 25,062 | | | | - | | | | 61,116 | |
| Asset retirement obligations | | | - | | | | 24,346 | | | | 785,768 | | | | - | | | | 810,114 | |
| Retirement benefits | | | 8,721 | | | | 54,415 | | | | - | | | | - | | | | 63,136 | |
| Property taxes | | | - | | | | 25,328 | | | | 22,767 | | | | - | | | | 48,095 | |
| Lease market valuation liability | | | - | | | | 353,210 | | | | - | | | | - | | | | 353,210 | |
| Other | | | 19,800 | | | | 21,829 | | | | - | | | | - | | | | 41,629 | |
| | | | 28,521 | | | | 515,182 | | | | 1,092,744 | | | | 800,972 | | | | 2,437,419 | |
| | | $ | 3,162,511 | | | $ | 4,452,888 | | | $ | 4,092,883 | | | $ | (3,286,018 | ) | | $ | 8,422,264 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Nine Months Ended September 30, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| NET CASH PROVIDED FROM OPERATING ACTIVITIES: | | $ | 47,463 | | | $ | 267,933 | | | $ | 247,054 | | | $ | (8,317 | ) | | $ | 554,133 | |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| New Financing- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | - | | | | 328,325 | | | | 209,050 | | | | - | | | | 537,375 | |
| Equity contribution from parent | | | 280,000 | | | | 675,000 | | | | 175,000 | | | | (850,000 | ) | | | 280,000 | |
| Short-term borrowings, net | | | 700,000 | | | | - | | | | 139,363 | | | | (91,677 | ) | | | 747,686 | |
| Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | (1,777 | ) | | | (286,776 | ) | | | (180,666 | ) | | | 8,317 | | | | (460,902 | ) |
| Short-term borrowings, net | | | - | | | | (91,677 | ) | | | - | | | | 91,677 | | | | - | |
| Common stock dividend payment | | | (43,000 | ) | | | - | | | | - | | | | - | | | | (43,000 | ) |
| Net cash provided from financing activities | | | 935,223 | | | | 624,872 | | | | 342,747 | | | | (841,683 | ) | | | 1,061,159 | |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | (38,481 | ) | | | (778,329 | ) | | | (600,395 | ) | | | - | | | | (1,417,205 | ) |
| Proceeds from asset sales | | | - | | | | 15,218 | | | | - | | | | - | | | | 15,218 | |
| Sales of investment securities held in trusts | | | - | | | | - | | | | 596,291 | | | | - | | | | 596,291 | |
| Purchases of investment securities held in trusts | | | - | | | | - | | | | (624,899 | ) | | | - | | | | (624,899 | ) |
| Loan repayments from (loans to) associated companies, net | | | (94,755 | ) | | | (38,399 | ) | | | 69,012 | | | | - | | | | (64,142 | ) |
| Investment in subsidiary | | | (850,000 | ) | | | - | | | | - | | | | 850,000 | | | | - | |
| Restricted funds for debt redemption | | | - | | | | (52,090 | ) | | | (29,550 | ) | | | - | | | | (81,640 | ) |
| Other | | | 550 | | | | (39,205 | ) | | | (260 | ) | | | - | | | | (38,915 | ) |
| Net cash used for investing activities | | | (982,686 | ) | | | (892,805 | ) | | | (589,801 | ) | | | 850,000 | | | | (1,615,292 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net change in cash and cash equivalents | | | - | | | | - | | | | - | | | | - | | | | - | |
| Cash and cash equivalents at beginning of period | | | 2 | | | | - | | | | - | | | | - | | | | 2 | |
| Cash and cash equivalents at end of period | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Nine Months Ended September 30, 2007 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| NET CASH PROVIDED FROM (USED FOR) | | | | | | | | | | | | | | | |
| OPERATING ACTIVITIES | | $ | (7,937 | ) | | $ | 350,927 | | | $ | 179,037 | | | $ | - | | | $ | 522,027 | |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| New Financing- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | - | | | | 1,328,919 | | | | - | | | | (1,328,919 | ) | | | - | |
| Equity contribution from parent | | | 700,000 | | | | 700,000 | | | | - | | | | (700,000 | ) | | | 700,000 | |
| Short-term borrowings, net | | | 223,942 | | | | - | | | | 13,128 | | | | (237,070 | ) | | | - | |
| Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
| Common stock | | | (600,000 | ) | | | - | | �� | | - | | | | - | | | | (600,000 | ) |
| Long-term debt | | | - | | | | (795,019 | ) | | | (315,155 | ) | | | - | | | | (1,110,174 | ) |
| Short-term borrowings, net | | | - | | | | (1,022,197 | ) | | | - | | | | 237,070 | | | | (785,127 | ) |
| Common stock dividend payment | | | (67,000 | ) | | | - | | | | - | | | | - | | | | (67,000 | ) |
| Net cash provided from (used for) financing activities | | | 256,942 | | | | 211,703 | | | | (302,027 | ) | | | (2,028,919 | ) | | | (1,862,301 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | (10,119 | ) | | | (332,499 | ) | | | (140,289 | ) | | | - | | | | (482,907 | ) |
| Proceeds from asset sales | | | - | | | | 12,990 | | | | - | | | | - | | | | 12,990 | |
| Proceeds from sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,328,919 | | | | 1,328,919 | |
| Sales of investment securities held in trusts | | | - | | | | - | | | | 521,535 | | | | - | | | | 521,535 | |
| Purchases of investment securities held in trusts | | | - | | | | - | | | | (552,779 | ) | | | - | | | | (552,779 | ) |
| Loan repayments from (loans to) associated companies, net | | | 460,023 | | | | (242,612 | ) | | | 292,896 | | | | - | | | | 510,307 | |
| Investment in subsidiary | | | (700,000 | ) | | | - | | | | | | | | 700,000 | | | | - | |
| Other | | | 1,091 | | | | (509 | ) | | | 1,627 | | | | - | | | | 2,209 | |
| Net cash provided from (used for) investing activities | | | (249,005 | ) | | | (562,630 | ) | | | 122,990 | | | | 2,028,919 | | | | 1,340,274 | |
| | | | | | | | | | | | | | | | | | | | | |
| Net change in cash and cash equivalents | | | - | | | | - | | | | - | | | | - | | | | - | |
| Cash and cash equivalents at beginning of period | | | 2 | | | | - | | | | - | | | | - | | | | 2 | |
| Cash and cash equivalents at end of period | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
PART II. OTHER INFORMATION
Pursuant to reporting requirements of respective financings, OE, CEI, TE and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q. Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither OE, CEI, TE 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 its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.
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.
