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The following is an excerpt from a 10-Q SEC Filing, filed by FIRSTENERGY CORP on 8/7/2008.
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FIRSTENERGY CORP - 10-Q - 20080807 - NOTES_TO_FINANCIAL_STATEMENT
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


1.  ORGANIZATION AND BASIS OF PRESENTATION

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 Companies. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform 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 8) 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.

The consolidated financial statements as of June 30, 2008 and for the three-month and six-month periods ended June 30, 2008 and 2007, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated August 7, 2008) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.

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. The pool of stock-based compensation tax benefits is calculated in accordance with SFAS 123(R). 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:

 
107

 


   
Three Months
 
Six Months
 
   
Ended June 30
 
Ended June 30
 
Reconciliation of Basic and Diluted Earnings per Share
 
2008
 
2007
 
2008
 
2007
 
   
(In millions, except per share amounts)
 
                           
Net income
 
$
263
 
$
338
 
$
539
 
$
628
 
                           
Average shares of common stock outstanding – Basic
   
304
   
304
   
304
   
309
 
Assumed exercise of dilutive stock options and awards
   
3
   
4
   
3
   
4
 
Average shares of common stock outstanding – Dilutive
   
307
   
308
   
307
   
313
 
                           
Basic earnings per share
 
$
0.86
 
$
1.11
 
$
1.77
 
$
2.03
 
Diluted earnings per share
 
$
0.85
 
$
1.10
 
$
1.75
 
$
2.01
 

3.  DIVESTITURES AND DISCONTINUED OPERATIONS

On March 7, 2008, FirstEnergy sold certain telecommunication assets, resulting in a net after-tax gain of $19.3 million. As a result of the sale, FirstEnergy adjusted goodwill by $1 million for the former GPU companies due to the realization of tax benefits that had been reserved in purchase accounting. The sale of assets did not meet the criteria for classification as discontinued operations as of June 30, 2008.

4.  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 June 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 consists 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.

 
108

 


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 June 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.

   
June 30, 2008
 
Recurring Fair Value Measures
 
Level 1
 
Level 2
 
Level 3
 
Total
 
   
(In millions)
 
Assets:
                         
    Derivatives
 
$
7
 
$
110
 
$
-
 
$
117
 
    Nuclear decommissioning trusts (1)
   
1,040
   
950
   
-
   
1,990
 
    Other investments (2)
   
21
   
309
   
-
   
330
 
    Total
 
$
1,068
 
$
1,369
 
$
-
 
$
2,437
 
                           
Liabilities:
                         
    Derivatives
 
$
-
 
$
123
 
$
-
 
$
123
 
    NUG contracts (3)
   
-
   
-
   
644
   
644
 
    Total
 
$
-
 
$
123
 
$
644
 
$
767
 

(1)   
Balance excludes $2 million of net receivables, payables and accrued income.
(2)   
Excludes $312 million of the cash surrender value of life insurance contracts.
(3)   
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 ICE 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 set forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three and six months ended June 30, 2008:

   
Three Months
   
Six Months
 
   
Ended June 30, 2008
   
Ended June 30, 2008
 
   
(In millions)
 
Balance at beginning of period
 
$
682
   
$
750
 
    Realized and unrealized gains (losses) (1)
   
(30
)
   
(88
)
    Purchases, sales, issuances and settlements, net (1)
   
(8
)
   
(18
)
    Net transfers to (from) Level 3
   
-
     
-
 
Balance as of June 30, 2008
 
$
644
   
$
644
 
                 
Change in unrealized gains (losses) relating to
               
    instruments held as of June 30, 2008
 
$
(30
)
 
$
(88
)
                 
(1)   Changes in the fair value of NUG contracts are completely offset by regulatory assets and do not impact earnings
 
 


 
109

 

Under FSP FAS 157-2, FirstEnergy has elected to defer, for one year, the election of SFAS 157 for financial assets and financial liabilities measured at fair value on a non-recurring basis. FirstEnergy is currently evaluating the impact of FAS 157 on those financial assets and financial liabilities measured at fair value on a non-recurring basis.

5.  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 on its Consolidated Balance Sheet at their fair value unless they meet the normal purchases and normal sales criteria. Derivatives that meet those criteria are accounted for at cost. The changes in the fair value of derivative instruments that do not meet the normal purchases and normal sales criteria 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 and natural gas purchases and anticipated interest payments associated with future debt issues. The effective portion of such hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings.

The net deferred losses of $78 million included in AOCL as of June 30, 2008, for derivative hedging activity, as compared to $75 million as of December 31, 2007, resulted from a net $15 million increase related to current hedging activity and a $12 million decrease due to net hedge losses reclassified to earnings during the six months ended June 30, 2008. Based on current estimates, approximately $28 million (after tax) of the net deferred losses on derivative instruments in AOCL as of June 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.

FirstEnergy has entered into swaps that have been designated as fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. As of June 30, 2008, FirstEnergy had interest rate swaps with an aggregate notional value of $150 million and a fair value of $(3) million.

During 2007 and the first six 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. During the first six months of 2008, FirstEnergy terminated swaps with a notional value of $650 million and entered into swaps with a notional value of $850 million. FirstEnergy paid $14 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 June 30, 2008, FirstEnergy had forward swaps with an aggregate notional amount of $600 million and a fair value of $6 million.

6.  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 June 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 June 30, 2008, the fair value of the decommissioning trust assets was approximately $2.0 billion.

 
110

 


The following tables analyze changes to the ARO balance during the three months and six months ended June 30, 2008 and 2007, respectively.

ARO Reconciliation
 
FirstEnergy
 
FES
 
OE
 
CEI
 
TE
 
JCP&L
 
Met-Ed
 
Penelec
 
   
(In millions)
 
Balance, April 1, 2008
 
$
1,287
 
$
824
 
$
95
 
$
2
 
$
29
 
$
91
 
$
163
 
$
83
 
Liabilities incurred
   
-
   
-
   
-
   
-
   
-
   
-
   
-
   
-
 
Liabilities settled
   
(1
)
 
(1
)
 
-
   
-
   
-
   
-
   
-
   
-
 
Accretion
   
21
   
13
   
1
   
-
   
-
   
1
   
3
   
1
 
Revisions in estimated cash flows
   
-
   
-
   
-
   
-
   
-
   
-
   
-
   
-
 
Balance, June 30, 2008
 
$
1,307
 
$
836
 
$
96
 
$
2
 
$
29
 
$
92
 
$
166
 
$
84
 
                                                   
Balance, April 1, 2007
 
$
1,208
 
$
772
 
$
89
 
$
2
 
$
27
 
$
86
 
$
153
 
$
78
 
Liabilities incurred
   
-
   
-
   
-
   
-
   
-
   
-
   
-
   
-
 
Liabilities settled
   
-
   
-
   
-
   
-
   
-
   
-
   
-
   
-
 
Accretion
   
21
   
13
   
2
   
-
   
-
   
1
   
3
   
1
 
Revisions in estimated cash flows
   
(1
)
 
(1
)
 
-
   
-
   
-
   
-
   
-
   
-
 
Balance, June 30, 2007
 
$
1,228
 
$
784
 
$
91
 
$
2
 
$
27
 
$
87
 
$
156
 
$
79
 

ARO Reconciliation
 
FirstEnergy
 
FES
 
OE
 
CEI
 
TE
 
JCP&L
 
Met-Ed
 
Penelec
 
   
(In millions)
 
Balance, January 1, 2008
 
$
1,267
 
$
810
 
$
94
 
$
2
 
$
28
 
$
90
 
$
161
 
$
82
 
Liabilities incurred
   
-
   
-
   
-
   
-
   
-
   
-
   
-
   
-
 
Liabilities settled
   
(1
)
 
(1
)
 
-
   
-
   
-
   
-
   
-
   
-
 
Accretion
   
41
   
27
   
2
   
-
   
1
   
2
   
5
   
2
 
Revisions in estimated cash flows
   
-
   
-
   
-
   
-
   
-
   
-
   
-
   
-
 
Balance, June 30, 2008
 
$
1,307
 
$
836
 
$
96
 
$
2
 
$
29
 
$
92
 
$
166
 
$
84
 
                                                   
Balance, January 1, 2007
 
$
1,190
 
$
760
 
$
88
 
$
2
 
$
27
 
$
84
 
$
151
 
$
77
 
Liabilities incurred
   
-
   
         -
   
-
   
-
   
-
   
-
   
-
   
-
 
Liabilities settled
   
-
   
-
   
-
   
-
   
-
   
-
   
-
   
-
 
Accretion
   
39
   
25
   
3
   
-
   
-
   
3
   
5
   
2
 
Revisions in estimated cash flows
   
(1
)
 
(1
)
 
-
   
-
   
-
   
-
   
-
   
-
 
Balance, June 30, 2007
 
$
1,228
 
$
784
 
$
91
 
$
2
 
$
27
 
$
87
 
$
156
 
$
79
 


7.  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 six months ended June 30, 2008 and 2007, consisted of the following:

   
Three Months
 
Six Months
 
   
Ended June 30
 
Ended June 30
 
Pension Benefits
 
2008
 
2007
 
2008
 
2007
 
   
(In millions)
 
Service cost
 
$
21
 
$
21
 
$
41
 
$
42
 
Interest cost
   
72
   
71
   
144
   
142
 
Expected return on plan assets
   
(116
)
 
(113
)
 
(231
)
 
(225
)
Amortization of prior service cost
   
3
   
3
   
5
   
5
 
Recognized net actuarial loss
   
1
   
11
   
3
   
21
 
Net periodic cost (credit)
 
$
(19
)
$
(7
)
$
(38
)
$
(15
)



 
111

 


   
Three Months
 
Six Months
 
   
Ended June 30
 
Ended June 30
 
Other Postretirement Benefits
 
2008
 
2007
 
2008
 
2007
 
   
(In millions)
 
Service cost
 
$
5
 
$
5
 
$
9
 
$
10
 
Interest cost
   
18
   
17
   
37
   
34
 
Expected return on plan assets
   
(13
)
 
(12
)
 
(26
)
 
(25
)
Amortization of prior service cost
   
(37
)
 
(37
)
 
(74
)
 
(74
)
Recognized net actuarial loss
   
12
   
11
   
24
   
23
 
Net periodic cost (credit)
 
$
(15
)
$
(16
)
$
(30
)
$
(32
)

Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. FES and the Companies 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 Companies for the three months and six months ended June 30, 2008 and 2007 were as follows:

   
Three Months
 
Six Months
 
   
Ended June 30
 
Ended June 30
 
Pension Benefit Cost (Credit)
 
2008
 
2007
 
2008
 
2007
 
   
(In millions)
 
FES
 
$
4
 
$
5
 
$
8
 
$
10
 
OE
   
(7
)
 
(4
)
 
(13
)
 
(8
)
CEI
   
(1
)
 
-
   
(3
)
 
1
 
TE
   
(1
)
 
-
   
(1
)
 
-
 
JCP&L
   
(4
)
 
(2
)
 
(8
)
 
(4
)
Met-Ed
   
(3
)
 
(2
)
 
(5
)
 
(4
)
Penelec
   
(3
)
 
(2
)
 
(7
)
 
(5
)
Other FirstEnergy subsidiaries
   
(4
)
 
(2
)
 
(9
)
 
(5
)
   
$
(19
)
$
(7
)
$
(38
)
$
(15
)

   
Three Months
 
Six Months
 
   
Ended June 30
 
Ended June 30
 
Other Postretirement Benefit Cost (Credit)
 
2008
 
2007
 
2008
 
2007
 
   
(In millions)
 
FES
 
$
(2
)
$
(2
)
$
(4
)
$
(5
)
OE
   
(2
)
 
(3
)
 
(3
)
 
(5
)
CEI
   
1
   
1
   
1
   
2
 
TE
   
1
   
1
   
2
   
2
 
JCP&L
   
(4
)
 
(4
)
 
(8
)
 
(8
)
Met-Ed
   
(3
)
 
(3
)
 
(5
)
 
(5
)
Penelec
   
(3
)
 
(3
)
 
(6
)
 
(6
)
Other FirstEnergy subsidiaries
   
(3
)
 
(3
)
 
(7
)
 
(7
)
   
$
(15
)
$
(16
)
$
(30
)
$
(32
)

8.  VARIABLE INTEREST ENTITIES

FIN 46R addresses the consolidation of VIEs, including special-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the entity's residual economic risks and rewards. FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary as defined by FIN 46R.

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.

 
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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 June 30, 2008:

   
Maximum Exposure
 
Discounted
Lease Payments, net
 
Net
Exposure
   
(in millions)
FES
 
$
1,339
 
$
1,189
 
$
150
OE
 
806
 
583
 
223
CEI
 
748
 
78
 
670
TE
 
748
 
413
 
335

In October 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. FGCO 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.

On May 30, 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant. On June 2, 2008, NGC purchased approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. Between June 2, 2008 and June 9, 2008, NGC purchased an additional 158.5 MW of additional 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 Companies and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately 30 long-term power purchase agreements with NUG entities. The agreements were 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 six months ended June 30, 2008 and 2007 are shown in the following table:

 
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Three Months
 
Six Months
 
   
Ended June 30
 
Ended June 30
 
   
2008
 
2007
 
2008
 
2007
 
   
(In millions)
 
JCP&L
 
$
22
 
$
21
 
$
41
 
$
41
 
Met-Ed
   
16
   
12
   
32
   
27
 
Penelec
   
8
   
7
   
17
   
15
 
Total
 
$
46
 
$
40
 
$
90
 
$
83
 

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 June 30, 2008, $385 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, which consists primarily of bondable transition property.

Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on 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.

9.  INCOME TAXES

On January 1, 2007, FirstEnergy adopted FIN 48, which provides guidance for accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. 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.

As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits was $268 million. FirstEnergy recorded a $2.7 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. 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. During the first six months of 2008 and 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of June 30, 2008, FirstEnergy expects that it is reasonably possible that approximately $155 million of the unrecognized benefits may be resolved within the next twelve months, of which $54 million to $134 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 net amount of interest accrued as of June 30, 2008 was $60 million, as compared to $53 million as of December 31, 2007.

 
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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 are expected to close before December 2008, but management anticipates certain items to be appealed. The IRS began auditing the year 2007 in February 2007 and the year 2008 in February 2008 under its Compliance Assurance Process experimental 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.

10.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A)   GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of June 30, 2008, outstanding guarantees and other assurances aggregated approximately $4.3 billion, consisting of parental guarantees - $0.9 billion, subsidiaries’ guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $0.6 billion.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of 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 June 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 or provision of an LOC may be required of the subsidiary. As of June 30, 2008, FirstEnergy's maximum exposure under these collateral provisions was $542 million.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $74 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. 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.

(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 SO 2 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 SO 2 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.

 
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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 SO 2 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. NO X 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 NO X reductions at FirstEnergy's facilities. The EPA's NO X Transport Rule imposes uniform reductions of NO X emissions (an approximate 85% reduction in utility plant NO X 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 NO X emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NO X budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

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.

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.  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, which was 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.  Although it remains liable for civil or criminal penalties and fines that may be assessed relating to events prior to the sale of the Homer City Power Station 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 intends to fully comply with the ACO, but, at this time, is unable to predict the outcome of this matter.

 
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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 NO X and SO 2 emissions in two phases (Phase I in 2009 for NO X , 2010 for SO 2 and Phase II in 2015 for both NO X and SO 2 ), ultimately capping SO 2 emissions in affected states to just 2.5 million tons annually and NO X 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 programs for SO 2 and NO X , which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. The future cost of compliance with these regulations may be substantial and will depend on 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 SO 2 and NO X 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.  The EPA must now petition for United States Supreme Court review of that ruling or 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.

W. H. Sammis Plant

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, are referred to as the NSR cases.

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NO X and SO 2 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. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. 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.

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.

 
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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 Environmental and Public Works Committees have 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 CO 2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO 2 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 CO 2 under the CAA.

FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions could require significant capital and other expenditures. The CO 2 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-CO 2 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. 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 June 30, 2008, FirstEnergy had approximately $2.0 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.

 
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The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site 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 June 30, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $95 million (JCP&L - $68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through June 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.   FirstEnergy is defending this action but is unable to predict the outcome of this matter.  No liability has been accrued as of June 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 one portion of 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.

 
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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. The NRC is expected to issue its draft supplemental Environmental Impact Statement and Safety Evaluation Report with open items in 2008. 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.

On July 22, 2008 and July 23, 2008, three complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania as well as in the Beaver County Court of Common Pleas 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. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.

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. Oral arguments have been requested and are expected to take place in the fall. 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.

 
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11.  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 Companies 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 Reliability First Corporation.  All of FirstEnergy’s facilities are located within the Reliability First region. FirstEnergy actively participates in the NERC and Reliability First 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, Reliability First 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, Reliabilit yFirst 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, Reliability First has 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 $194 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 will now be addressed in the Ohio Companies’ comprehensive ESP filing, as described below, unless the MRO is implemented.

 
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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. On January 3, 2008, the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. 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 $51 million of interest costs deferred through June 30, 2008 ($0.10 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 $430 million in 2009, $490 million in 2010 and $550 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 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);

 
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·  
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 1 st and September 30 th for capacity purchases required to meet FERC, NERC, MISO and other applicable standards for planning reserve margin requirements;

·  
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.

The Ohio Companies’ MRO filing outlines a CBP for providing retail generation supply if the ESP is not approved and implemented. The CBP would use a “slice-of-system” approach where suppliers bid on tranches (approximately 100 MW) of the Ohio Companies’ total customer load. The Ohio Companies have requested PUCO approval of the MRO application by late October 2008, to allow for the necessary time to conduct the CBP in order for rates to be effective January 1, 2009.  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.

(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.

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).

 
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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. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.

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 March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. Bids on the two RFPs for residential customers’ load were approved by the PPUC on April 16, 2008 and May 16, 2008. On May 20, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for residential customers which the PPUC certified on May 21, 2008. The new rates were effective June 1, 2008.

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. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. 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. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy; however, consideration of these issues was postponed until the legislature returns to session in fall 2008. The final form of this pending legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations. However, Met-Ed and Penelec intend to file rate mitigation plans with the PPUC later this year.

(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 June 30, 2008, the accumulated deferred cost balance totaled approximately $293 million.

 
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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 draft EMP 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 22.5% of the state’s electricity needs with renewable energy by 2020;

·  
develop low carbon emitting, efficient power plants and close the gap between the supply and demand for electricity; and

·  
invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey.

Following the public hearings and comment period which extended into July 2008, a final EMP will be issued to 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.

 
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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. The FERC’s action on the settlement agreement is pending. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. Reply briefs and briefs on exceptions are due in the merchant proceeding in July and August, respectively, with an initial decision by the Presiding Judge to follow. 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. A rehearing request by AEP is pending before the FERC.

 
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Distribution of   MISO Network Service Revenues

Effective February 1, 2008, the MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation.  This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.

Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be charged by MISO for network service. On February 1, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.

On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. On May 12, 2008, the FERC issued an order approving this amendment.

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. This filing would permit 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. MISO has since notified the FERC that the start of its ASM will be delayed until September 9, 2008.

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.

Interconnection Agreement with AMP-Ohio

On May 4, 2007, AMP-Ohio filed a complaint in Franklin County, Ohio Common Pleas Court against FirstEnergy and TE seeking a declaratory judgment that the defendants may not terminate certain portions of a wholesale power Interconnection Agreement dated May 1, 1989 between AMP-Ohio and TE, nor further modify the rates and charges for power under that agreement. TE has served notice of termination of the Interconnection Agreement on AMP-Ohio to be effective December 31, 2008. AMP-Ohio claims that FirstEnergy, on behalf of TE, waived any right to terminate the Interconnection Agreement according to the terms of a June 6, 1997 merger settlement agreement with AMP-Ohio. Both the Interconnection Agreement and merger settlement agreement were approved by the FERC. On June 15, 2007, TE filed notice of removal of the case to United States District Court for the Southern District of Ohio. On July 11, 2007, TE moved to dismiss on the grounds that the FERC has exclusive jurisdiction over the subject matter of the complaint, or alternatively, primary jurisdiction over this matter. Responsive pleadings were filed by both parties and on March 31, 2008, the district court issued an order dismissing the matter for lack of subject matter jurisdiction. However, AMP-Ohio informed TE that it continues to object to cancellation of the power sales provisions of the Interconnection Agreement.

 
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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. TE has requested FERC action on both filings and expects the FERC to act on this request in the third quarter of 2008.

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. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.

On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne to pay the PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FirstEnergy and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed MISO to submit detailed plans to integrate Duquesne into MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 1, 2008.  On July 3, 2008, Duquesne and MISO filed a proposed plan for integrating Duquesne into MISO.  On July 24, 2008, numerous parties filed comments and protests to the proposed plan. FirstEnergy filed comments identifying numerous issues that must be addressed and resolved before Duquesne can transition to MISO. FirstEnergy continues to evaluate the impact of Duquesne’s withdrawal from PJM on its operations and financial condition; however, the full consequences cannot be determined until the FERC rules on the pending issues.

On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein 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. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. Given that the FERC outlined the conditions under which FirstEnergy could bid the unit into the auction and FirstEnergy complied with the FERC’s conditions, FirstEnergy does not anticipate that the FERC will grant the relief requested in the pleadings.  Based on this expectation, FirstEnergy believes that the auction results would not be changed.

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. 

 
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If the FERC were to rule unfavorably on this matter, the impact for the period ended June 30, 2008, would not be material to FirstEnergy’s results of operations, cash flows or financial position, as FES only began collecting RPM revenues for the Beaver Valley Power Station on June 1, 2008. However, such an unfavorable ruling by the FERC could have a material adverse impact on the revenues of the Beaver Valley Power Station in subsequent periods if these proceedings were to result in a significant loss of FES’ RPM revenues.

FES believes that the FERC is unlikely to grant the relief sought in the RPM Buyers’ complaint, since it largely deals with legal issues concerning the fundamentals of the RPM markets that are already at issue in a separate D.C. Circuit Court appellate proceeding. Nevertheless, FES is unable to predict the outcome of these proceedings or the resulting effect on FirstEnergy’s or FES’ results of operations, cash flows or financial position.

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. A FERC decision on this filing is expected this fall.

Organized Wholesale Power Markets

On February 21, 2008, the FERC issued a NOPR through which it proposes to adopt new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FirstEnergy does not believe that the proposed rule will have a significant impact on its operations. Comments on the NOPR were filed on April 21, 2008.
 
12.  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 the 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 tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

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.

 
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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 fiscal years beginning on or after December 15, 2008. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

 
SFAS 162 - “The Hierarchy of Generally Accepted Accounting Principles”

In May 2008, the FASB issued SFAS 162, which is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP. The FASB believes that the GAAP hierarchy should be directed to reporting entities, not the independent auditors, because reporting entities are responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. This Statement is effective 60 days following the SEC’s approval of the PCAOB amendments to U.S. Auditing Standards Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles , which has not yet occurred. The Statement will not have an impact on FirstEnergy’s financial statements.

13.  SEGMENT INFORMATION

FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The “Other” segment primarily consists of telecommunications services. The assets and revenues for the 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.

 
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Segment Financial Information
                               
               
Ohio
                   
   
Energy
   
Competitive
   
Transitional
                   
   
Delivery
   
Energy
   
Generation
         
Reconciling
       
Three Months Ended
 
Services
   
Services
   
Services
   
Other
   
Adjustments
   
Consolidated
 
   
(In millions)
 
June 30, 2008
                                   
External revenues
  $ 2,182     $ 375     $ 683     $ 20     $ (15 )   $ 3,245  
Internal revenues
    -       704       -       -       (704 )     -  
Total revenues
    2,182       1,079       683       20       (719 )     3,245  
Depreciation and amortization
    241       59       11       1       4       316  
Investment income
    40       (8 )     (1 )     6       (21 )     16  
Net interest charges
    99       28       -       -       48       175  
Income taxes
    129       45       13       (1 )     (26 )     160  
Net income
    193       66       19       26       (41 )     263  
Total assets
    23,423       9,240       266       281       335       33,545  
Total goodwill
    5,582       24       -       -       -       5,606  
Property additions
    196       683       -       9       18       906  
                                                 
June 30, 2007
                                               
External revenues
  $ 2,095     $ 398     $ 625     $ 9     $ (18 )   $ 3,109  
Internal revenues
    -       691       -       -       (691 )     -  
Total revenues
    2,095       1,089       625       9       (709 )     3,109  
Depreciation and amortization
    249       51       (49 )     1       5       257  
Investment income
    62       5       -       -       (37 )     30  
Net interest charges
    116       42       -       1       39       198  
Income taxes
    141       96       19       (3 )     (31 )     222  
Net income
    207       142       30       6       (47 )     338  
Total assets
    23,602       7,284       260       236       651       32,033  
Total goodwill
    5,874       24       -       -       -       5,898  
Property additions
    245       139       -       2       15       401  
                                                 
Six Months Ended
                                               
                                                 
June 30, 2008
                                               
External revenues
  $ 4,394     $ 704     $ 1,390     $ 60     $ (26 )   $ 6,522  
Internal revenues
    -       1,480       -       -       (1,480 )     -  
Total revenues
    4,394       2,184       1,390       60       (1,506 )     6,522  
Depreciation and amortization
    496       112       15       1       9       633  
Investment income
    85       (14 )     -       6       (44 )     33  
Net interest charges
    202       55       -       -       89       346  
Income taxes
    248       103       28       13       (45 )     347  
Net income
    372       153       42       48       (76 )     539  
Total assets
    23,423       9,240       266       281       335       33,545  
Total goodwill
    5,582       24       -       -       -       5,606  
Property additions
    451       1,145       -       21       -       1,617  
                                                 
June 30, 2007
                                               
External revenues
  $ 4,135     $ 719     $ 1,245     $ 20     $ (37 )   $ 6,082  
Internal revenues
    -       1,404       -       -       (1,404 )     -  
Total revenues
    4,135       2,123       1,245       20       (1,441 )     6,082  
Depreciation and amortization
    469       102       (64 )     2       11       520  
Investment income
    132       8       1       -       (78 )     63  
Net interest charges
    223       92       1       2       60       378  
Income taxes
    289       160       35       2       (64 )     422  
Net income
    425       240       53       7       (97 )     628  
Total assets
    23,602       7,284       260       236       651       32,033  
Total goodwill
    5,874       24       -       -       -       5,898  
Property additions
    400       263       -       3       31       697  
 
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.

 
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  14. 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 six-month periods ended June 30, 2008 and 2007, consolidating balance sheets as of June 30, 2008 and December 31, 2007 and condensed consolidating statements of cash flows for the six-months ended June 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.

 
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FIRSTENERGY SOLUTIONS CORP.
                               
CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                               
For the Three Months Ended June 30, 2008
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)
 
                               
REVENUES
  $ 1,064,627     $ 565,225     $ 287,028     $ (845,602 )   $ 1,071,278  
                                         
EXPENSES:
                                       
Fuel
    3,605       277,192       29,753       -       310,550  
Purchased power from non-affiliates
    220,339       -       -       -       220,339  
Purchased power from affiliates
    842,670       2,932       34,528       (845,602 )     34,528  
Other operating expenses
    29,842       124,173       121,534       12,189       287,738  
Provision for depreciation
    1,600       30,027       25,893       (1,360 )     56,160  
General taxes
    4,727       11,504       3,564       -       19,795  
Total expenses
    1,102,783       445,828       215,272       (834,773 )     929,110  
                                         
OPERATING INCOME (LOSS)
    (38,156 )     119,397       71,756       (10,829 )     142,168  
                                         
OTHER INCOME (EXPENSE):
                                       
Miscellaneous income (expense), including
                                       
net income from equity investees
    98,590       489       (9,449 )     (91,704 )     (2,074 )
 Interest expense - affiliates
    (50 )     (7,920 )     (2,758 )     -       (10,728 )
 Interest expense - other
    (6,663 )     (23,697 )     (10,632 )     16,487       (24,505 )
Capitalized interest
    28       9,856       657       -       10,541  
Total other income (expense)
    91,905       (21,272 )     (22,182 )     (75,217 )     (26,766 )
                                         
INCOME BEFORE INCOME TAXES
    53,749       98,125       49,574       (86,046 )     115,402  
                                         
INCOME TAXES (BENEFIT)
    (14,345 )     38,467       20,838       2,348       47,308  
                                         
NET INCOME
  $ 68,094     $ 59,658     $ 28,736     $ (88,394 )   $ 68,094  
 

 
 
133

 
 

 
FIRSTENERGY SOLUTIONS CORP.
                               
CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                               
For the Three Months Ended June 30, 2007
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)
 
                               
REVENUES
  $ 1,074,858     $ 453,553     $ 279,092     $ (738,772 )   $ 1,068,731  
                                         
EXPENSES:
                                       
Fuel
    7,513       235,653       25,714       -       268,880  
Purchased power from non-affiliates
    162,873       -       -       -       162,873  
Purchased power from affiliates
    731,260       57,291       20,806       (738,772 )     70,585  
Other operating expenses
    30,519       65,694       136,932       -       233,145  
Provision for depreciation
    469       25,239       22,812       -       48,520  
General taxes
    5,602       9,050       6,258       -       20,910  
Total expenses
    938,236       392,927       212,522       (738,772 )     804,913  
                                         
OPERATING INCOME
    136,622       60,626       66,570       -       263,818  
                                         
OTHER INCOME (EXPENSE):
                                       
Miscellaneous income (expense), including
                                       
 net income from equity investees
    74,781       (622 )     4,215       (63,005 )     15,369  
Interest expense - affiliates
    -       (17,990 )     (4,827 )     -       (22,817 )
Interest expense - other
    (5,773 )     (6,116 )     (9,804 )     -       (21,693 )
Capitalized interest
    6       3,056       1,361       -       4,423  
Total other income (expense)
    69,014       (21,672 )     (9,055 )     (63,005 )     (24,718 )
                                         
INCOME BEFORE INCOME TAXES
    205,636       38,954       57,515       (63,005 )     239,100  
                                         
INCOME TAXES
    54,220       12,892       20,572       -       87,684  
                                         
NET INCOME
  $ 151,416     $ 26,062     $ 36,943     $ (63,005 )   $ 151,416  
 

 
 
134

 

 

FIRSTENERGY SOLUTIONS CORP.
                               
CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                               
For the Six Months Ended June 30, 2008
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)
 
                               
REVENUES
  $ 2,164,475     $ 1,132,926     $ 612,712     $ (1,739,719 )   $ 2,170,394  
                                         
EXPENSES: