261

ATSI was organized under the laws of the State of Ohio in 1998. ATSI owns transmission assets that were formerly owned by the Ohio Companies and Penn. ATSI owns major, high-voltage transmission facilities, which consist of approximately 5,821 pole miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV. Effective October 1, 2003, ATSI transferred operational control of its transmission facilities to MISO. With its affiliation with MISO, ATSI plans, operates, and maintains its transmission system in accordance with NERC reliability standards, and applicable regulatory agencies to ensure reliable service to customers.

OE

Year Ended
December 31, 2007
As Previously As
Reported Restated
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 197,166 $ 197,166
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 77,405 77,405
Amortization of regulatory assets 191,885 191,885
Deferral of new regulatory assets (177,633 ) (177,633 )
Nuclear fuel and lease amortization 33 33
Amortization of lease costs (7,425 ) (7,425 )
Deferred income taxes and investment tax credits, net 423 423
Accrued compensation and retirement benefits (46,313 ) (46,313 )
Pension trust contributions (20,261 ) (20,261 )
Decrease (increase) in operating assets-
Receivables (57,461 ) (57,461 )
Prepayments and other current assets 3,265 3,265
Increase (decrease) in operating liabilities-
Accounts payable 65,649 15,649
Accrued taxes (81,079 ) (81,079 )
Accrued interest (2,334 ) (2,334 )
Electric service prepayment programs (39,861 ) (39,861 )
Other 6,096 6,096
Net cash provided from operating activities 109,555 59,555

CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Common stock (500,000 ) (500,000 )
Long-term debt (112,497 ) (112,497 )
Short-term borrowings, net (114,475 ) (114,475 )
Dividend Payments-
Common stock (150,000 ) (100,000 )
Net cash used for financing activities (876,972 ) (826,972 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (145,311 ) (145,311 )
Sales of investment securities held in trusts 37,736 37,736
Purchases of investment securities held in trusts (43,758 ) (43,758 )
Loans to associated companies, net (79,115 ) (79,115 )
Collection of principal on long-term notes receivable 960,327 960,327
Cash investments 37,499 37,499
Other 59 59
Net cash provided from investing activities 767,437 767,437

Net increase in cash and cash equivalents $ 20 $ 20
JCP&L was organized under the laws of the State of New Jersey in 1925 and owns property and does business as an electric public utility in that state. JCP&L provides transmission and distribution services in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.6 million. JCP&L complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and the NJBPU.

Met-Ed was organized under the laws of the Commonwealth of Pennsylvania in 1922 and owns property and does business as an electric public utility in that state. Met-Ed provides transmission and distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million. Met-Ed complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.

Penelec was organized under the laws of the Commonwealth of Pennsylvania in 1919 and owns property and does business as an electric public utility in that state. Penelec provides transmission and distribution services in 17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.6 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, also serves customers in Waverly, New York and its vicinity. Penelec complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.

FESC provides legal, financial and other corporate support services to affiliated FirstEnergy companies.

Reference is made to Note 15, Segment Information, of the Notes to Consolidated Financial Statements contained in Item 8 for information regarding FirstEnergy's reportable segments.

Utility Regulation

State Regulation

Each of the Utilities’ retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the state in which each company operates – in Ohio by the PUCO, in New Jersey by the NJBPU and in Pennsylvania by the PPUC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.

As a competitive retail electric supplier serving retail customers in Ohio, Pennsylvania, Maryland, Michigan, and Illinois, FES is subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES and its public utility affiliates. In addition, if FES or any of its subsidiaries were to engage in the construction of significant new generation facilities, they would also be subject to state siting authority.

Federal Regulation

With respect to their wholesale and interstate electric operations and rates, the Utilities, ATSI, FES, FGCO and NGC are subject to regulation by the FERC. Under the FPA, the FERC regulates rates for interstate sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. The FERC regulations require ATSI, Met-Ed, JCP&L and Penelec to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission service over ATSI’s facilities is provided by MISO under its open access transmission tariff, and transmission service over Met-Ed’s, JCP&L’s and Penelec’s facilities is provided by PJM under its open access transmission tariff. The FERC also regulates unbundled transmission service to retail customers.

The FERC regulates the sale of power for resale in interstate commerce by granting authority to public utilities to sell wholesale power at market-based rates upon a showing that the seller cannot exert market power in generation or transmission. FES, FGCO and NGC have been authorized by the FERC to sell wholesale power in interstate commerce and have a market-based tariff on file with the FERC. By virtue of this tariff and authority to sell wholesale power, each company is regulated as a public utility under the FPA. However, consistent with its historical practice, the FERC has granted FES, FGCO and NGC a waiver from most of the reporting, record-keeping and accounting requirements that typically apply to traditional public utilities. Along with market-based rate authority, the FERC also granted FES, FGCO and NGC blanket authority to issue securities and assume liabilities under Section 204 of the FPA. As a condition to selling electricity on a wholesale basis at market-based rates, FES, FGCO and NGC, like all other entities granted market-based rate authority, must file electronic quarterly reports with the FERC, listing its sales transactions for the prior quarter.

272

CEI

Year Ended
December 31, 2007
As Previously As
Reported Restated
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 276,412 $ 276,412
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 75,238 75,238
Amortization of regulatory assets 144,370 144,370
Deferral of new regulatory assets (149,556 ) (149,556 )
Nuclear fuel and capital lease amortization 235 235
Deferred rents and lease market valuation liability (357,679 ) (357,679 )
Deferred income taxes and investment tax credits, net (22,767 ) (22,767 )
Accrued compensation and retirement benefits 3,196 3,196
Pension trust contributions (24,800 ) (24,800 )
Decrease (increase) in operating assets-
Receivables 209,426 209,426
Prepayments and other current assets (152 ) (152 )
Increase (decrease) in operating liabilities-
Accounts payable (216,638 ) (316,638 )
Accrued taxes (33,659 ) (33,659 )
Accrued interest (5,138 ) (5,138 )
Electric service prepayment programs (24,443 ) (24,443 )
Other 471 471
Net cash used for operating activities (125,484 ) (225,484 )

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 247,362 247,362
Short-term borrowings, net 277,581 277,581
Redemptions and Repayments-
Long-term debt (493,294 ) (493,294 )
Dividend Payments-
Common stock (304,000 ) (204,000 )
Net cash used for financing activities (272,351 ) (172,351 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (149,131 ) (149,131 )
Loan repayments from associated companies, net 6,714 6,714
Collection of principal on long-term notes receivable 486,634 486,634
Investments in lessor notes 56,179 56,179
Other (2,550 ) (2,550 )
Net cash provided from investing activities 397,846 397,846

Net increase in cash and cash equivalents $ 11 $ 11

TE
Year Ended
December 31, 2007
As Previously As
Reported Restated
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 91,239 $ 91,239
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 36,743 36,743
Amortization of regulatory assets 104,348 104,348
Deferral of new regulatory assets (62,664 ) (62,664 )
Nuclear fuel and capital lease amortization 23 23
Deferred rents and lease market valuation liability 265,981 265,981
Deferred income taxes and investment tax credits, net (26,318 ) (26,318 )
Accrued compensation and retirement benefits 5,276 5,276
Pension trust contributions (7,659 ) (7,659 )
Decrease (increase) in operating assets-
Receivables (64,489 ) (64,489 )
Prepayments and other current assets (13 ) (13 )
Increase (decrease) in operating liabilities-
Accounts payable 43,722 8,722
Accrued taxes (14,954 ) (14,954 )
Accrued interest (1,350 ) (1,350 )
Electric service prepayment programs (10,907 ) (10,907 )
Other 5,165 5,165
Net cash provided from operating activities 364,143 329,143

CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt (85,797 ) (85,797 )
Short-term borrowings, net (153,567 ) (153,567 )
Dividend Payments-
Common stock (120,000 ) (85,000 )
Net cash used for financing activities (359,364 ) (324,364 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (58,871 ) (58,871 )
Loans to associated companies (51,002 ) (51,002 )
Collection of principal on long-term notes receivable 91,308 91,308
Redemption of lessor notes 14,847 14,847
Sales of investment securities held in trusts 44,682 44,682
Purchases of investment securities held in trusts (47,853 ) (47,853 )
Other 2,110 2,110
Net cash used for investing activities (4,779 ) (4,779 )

Net change in cash and cash equivalents $ - $ -

PENELEC

Year Ended
December 31, 2007
As Previously As
Reported Restated
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 92,938 $ 92,938
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 49,558 49,558
Amortization of regulatory assets 55,863 55,863
Deferral of new regulatory assets (9,102 ) (9,102 )
Deferred costs recoverable as regulatory assets (71,939 ) (71,939 )
Deferred income taxes and investment tax credits, net 10,713 10,713
Accrued compensation and retirement benefits (20,830 ) (20,830 )
Pension trust contributions (13,436 ) (13,436 )
Decrease in operating assets-
Receivables 18,771 18,771
Prepayments and other current assets 1,159 1,159
Increase (decrease) in operating liabilities-
Accounts payable (4,513 ) (59,513 )
Accrued taxes 4,743 4,743
Accrued interest 5,943 5,943
Other 13,125 13,125
Net cash provided from operating activities 132,993 77,993

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 296,899 296,899
Short-term borrowings, net 15,662 15,662
Redemptions and Repayments-
Common Stock (200,000 ) (200,000 )
Dividend Payments-
Common stock (125,000 ) (70,000 )
Net cash provided from (used for) financing activities (12,439 ) 42,561

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (94,991 ) (94,991 )
Loan repayments from associated companies, net 3,235 3,235
Sales of investment securities held in trusts 175,222 175,222
Purchases of investment securities held in trusts (199,375 ) (199,375 )
Other, net (4,643 ) (4,643 )
Net cash used for investing activities (120,552 ) (120,552 )

Net increase in cash and cash equivalents $ 2 $ 2

The nuclear generating facilities owned and leased by NGC are subject to extensive regulation by the NRC. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security and environmental and radiological aspects of those stations. The NRC may modify, suspend or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of the licenses. FENOC is the licensee for these plants and has direct compliance responsibility for NRC matters. FES controls the economic dispatch of NGC’s plants. See “Nuclear Regulation” below.

~~2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~

~~(A) ACCOUNTING FOR THE EFFECTS OF REGULATION~~Regulatory Accounting

The ~~Companies account~~Utilities and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Utilities' respective transition and regulatory plans. Based on those plans, the Utilities continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Utilities continue the application of SFAS 71 to those operations.

FirstEnergy accounts for the effects of regulation through the application of SFAS 71 to its operating utilities since their rates:

▪

are established by a third-party regulator with the authority to set rates that bind customers;

▪

are cost-based; and

▪

can be charged to and collected from customers.

An enterprise meeting all of these criteria capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. SFAS 71 is applied only to the parts of the business that meet the above criteria. If a portion of the business applying SFAS 71 no longer meets those requirements, previously recorded net regulatory assets are removed from the balance sheet in accordance with the guidance in SFAS 101.

In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the ~~Companies'~~Utilities' respective state regulatory plans. These provisions include:

▪

restructuring the electric generation business and allowing the ~~Companies'~~Utilities' customers to select a competitive electric generation supplier other than the ~~Companies;~~Utilities;

▪

establishing or defining the PLR obligations to customers in the ~~Companies'~~Utilities' service areas;

▪

providing the ~~Companies~~Utilities with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

▪

itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges;

▪

continuing regulation of the ~~Companies'~~Utilities' transmission and distribution systems; and

▪

requiring corporate separation of regulated and unregulated business activities.

~~Regulatory Assets~~

The Companies recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $140 million as of December 31, 2007 (JCP&L - $84 million, Met-Ed - $54 million and Penelec - $2 million). Regulatory assets not earning a current return will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec.

~~Regulatory assets on the Companies' Consolidated Balance Sheets are comprised of the following:~~

Regulatory Assets * OE CEI TE JCP&L Met-Ed
December 31, 2007
(In millions)
Regulatory transition costs
$ 197 $ 227 $ 71 $ 1,630 $ 237
Customer shopping incentives
91 393 32 - -
Customer receivables (payables) for future income taxes
101 18 (1 ) 51 126
Loss (Gain) on reacquired debt
23 2 (3 ) 25 10
Employee postretirement benefit costs
- 8 4 17 10
Nuclear decommissioning, decontamination

and spent fuel disposal costs
- - - - (115 )
Asset removal costs
(6 ) (18 ) (11 ) (148 ) -
Property losses and unrecovered plant costs
- - - 9 -
MISO/PJM transmission costs
56 34 24 - 226
Fuel costs RCP
111 77 33 - -
Distribution costs RCP
148 122 51 - -
Other
16 8 4 12 1
Total
$ 737 $ 871 $ 204 $ 1,596 $ 495

December 31, 2006
Regulatory transition costs
$ 280 $ 360 $ 134 $ 2,207 $ 285
Customer shopping incentives
174 368 61 - -
Customer receivables (payables) for future income taxes
81 3 (4 ) 22 116
Societal benefits charge
- - - 11 -
Loss (Gain) on reacquired debt
24 - (3 ) 11 11
Employee postretirement benefit costs
- 10 5 20 12
Nuclear decommissioning, decontamination

and spent fuel disposal costs
- - - (1 ) (144 )
Asset removal costs
(2 ) (12 ) (5 ) (148 ) -
Property losses and unrecovered plant costs
- - - 19 -
MISO/PJM transmission costs
44 26 16 - 127
Fuel costs RCP
57 39 17 - -
Distribution costs RCP
74 57 24 - -
Other
9 4 3 11 2
Total
$ 741 $ 855 $ 248 $ 2,152 $ 409

Penn had net regulatory liabilities of approximately $67 million and $68 million as of December 31, 2007 and 2006, respectively. Penelec had net regulatory liabilities of approximately $74 million and $96 million as of December 31, 2007 and 2006, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

In accordance with the RCP, recovery of the aggregate of the regulatory transition costs and the Extended RTC (deferred customer shopping incentives and interest costs) amounts are expected to be complete for OE and TE by December 31, 2008. CEI's recovery of regulatory transition costs is projected to be complete by April 2009 at which time recovery of its Extended RTC will begin, with recovery estimated to be complete as of December 31, 2010. At the end of their respective recovery periods, any remaining unamortized regulatory transition costs and Extended RTC balances will be reduced by applying any remaining cost of removal regulatory liability balances -- any remaining regulatory transition costs and Extended RTC balances will be written off. The RCP allows the Ohio Companies to defer and capitalize certain distribution costs during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the years 2006, 2007 and 2008. These deferrals will be recovered in distribution rates effective on or after January 1, 2009. In addition, the Ohio Companies deferred certain fuel costs through December 31, 2007 that were incurred above the amount collected through a fuel recovery mechanism in accordance with the RCP (see Note 9(B)).

~~Transition Cost Amortization~~

The Ohio Companies amortize transition costs using the effective interest method. Extended RTC amortization is equal to the related revenue recovery that is recognized. The following table provides the estimated net amortization of regulatory transition costs and Extended RTC amounts (including associated carrying charges) under the RCP for the period 2008 through 2010:

Amortization
Period

OE

CEI

TE

(In millions)
2008 $ 207 $ 126 $ 113
2009 - 212 -
2010 - 273 -
Total Amortization $ 207 $ 611 $ 113

JCP&L's and Met-Ed's regulatory transition costs include the deferral of above-market costs for power supplied from NUGs of $875 million for JCP&L (recovered through BGS and MTC revenues) and $185 million for Met-Ed (recovered through CTC revenues). The liability for JCP&L's projected above-market NUG costs and corresponding regulatory asset are adjusted to fair value at the end of each quarter. Recovery of the remaining regulatory transition costs is expected to continue pursuant to various regulatory proceedings in New Jersey and Pennsylvania (See Note 9).

~~(B) REVENUES AND RECEIVABLES~~

Electric service provided to FES and the Companies' retail customers is metered on a cycle basis. Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided between the last meter reading and the end of the month. This estimate includes many factors including historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, FES and the Companies accrue the estimated unbilled amount receivable as revenue and reverse the related prior period estimate.

Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2007 with respect to any particular segment of customers. Billed and unbilled customer receivables for FES and the Companies as of December 31, 2007 and 2006 are shown below.

Customer Receivables FES OE CEI TE JCP&L Met-Ed Penelec
December 31, 2007 (In millions)
Billed $ 107 $ 143 $ 144 $ - $ 162 $ 80 $ 75
Unbilled 27 106 107 - 159 63 62
Total $ 134 $ 249 $ 251 $ - $ 321 $ 143 $ 137
December 31, 2006
Billed $ 104 $ 127 $ 137 $ 1 $ 128 $ 70 $ 69
Unbilled 26 108 108 - 126 57 58
Total $ 130 $ 235 $ 245 $ 1 $ 254 $ 127 $ 127

~~(C) EMISSION ALLOWANCES~~

~~FES holds emission allowances for SO~~2 ~~and NO~~X ~~in order to comply with programs implemented by the EPA designed to regulate emissions of SO~~2 ~~and NO~~X produced by power plants. Emission allowances are either granted by the EPA at zero cost or are purchased at fair value as needed to meet emission requirements. Emission allowances are not purchased with the intent of resale. Emission allowances eligible to be used in the current year are recorded in materials and supplies inventory at the lesser of weighted average cost or market value. Emission allowances eligible for use in future years are recorded as other investments. FES recognizes emission allowance costs as fuel expense during the periods that emissions are produced by its generating facilities. Excess emission allowances that are not needed to meet emission requirements may be sold and are reported as a reduction to other operating expenses.

~~(D) PROPERTY, PLANT AND EQUIPMENT~~

Property, plant and equipment reflects original cost (except for nuclear generating assets which were adjusted to fair value in accordance with SFAS 144), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FES' accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.

FES and the Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite rates for FES and the Companies electric plant in 2007, 2006 and 2005 are shown in the following table:

Annual Composite
Depreciation Rate
2007 2006 2005
OE
2.9 % 2.8 % 2.1 %
CEI
3.6 3.2 2.9
TE
3.9 3.8 3.1
Penn
2.3 2.6 2.4
JCP&L
2.1 2.1 2.2
Met-Ed
2.3 2.3 2.4
Penelec
2.3 2.3 2.6
FGCO
4.0 4.1 N/A
NGC
2.8 2.7 N/A

~~Jointly-Owned Generating Stations~~

~~JCP&L holds a 50% ownership interest in Yards Creek Pumped Storage Facility with a net book value of approximately $19.5 million as of December 31, 2007.~~

~~Asset Retirement Obligations~~

FES and the Companies recognize liabilities for retirement obligations associated with tangible assets in accordance with SFAS 143 and FIN 47. These standards require recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and depreciated over time, as described further in Note 11.

~~Nuclear Fuel~~

FES property, plant and equipment includes nuclear fuel recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. Nuclear fuel is amortized based on the units of production method.

~~(E) ASSET IMPAIRMENTS~~

~~Long-Lived Assets~~

FES and the Companies evaluate the carrying value of their long-lived assets when events or circumstances indicate that the carrying amount may not be recoverable. In accordance with SFAS 144, the carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If an impairment exists, a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. Fair value is estimated by using available market valuations or the long-lived asset's expected future net discounted cash flows. The calculation of expected cash flows is based on estimates and assumptions about future events.

~~Goodwill~~

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FES and the Companies evaluate their goodwill for impairment at least annually and make such evaluations more frequently if indicators of impairment arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment is indicated, a loss is recognized - calculated as the difference between the implied fair value of goodwill and the carrying value of goodwill. FES' and the Companies' 2007 annual review was completed in the third quarter of 2007 with no impairment indicated. In the third quarter of 2007, JCP&L, Met-Ed and Penelec adjusted goodwill due to the realization of tax benefits that had been reserved in purchase accounting.

FES' and the Companies' 2006 annual review was completed in the third quarter of 2006 with no impairment indicated. On January 11, 2007, the PPUC issued its order related to the comprehensive rate filing made by Met-Ed and Penelec on April 10, 2006 (see Note 9). The rate increase granted was substantially lower than the amounts Met-Ed and Penelec had requested. Prior to issuing the order, the PPUC conducted an informal, nonbinding polling of Commissioners at its public meeting on December 21, 2006 that indicated the rate increase ultimately granted would be substantially below the amounts requested. As a result of the polling, Met-Ed and Penelec determined that an interim review of goodwill would be required. As a result, Met-Ed recognized an impairment charge of $355 million in the fourth quarter of 2006. No impairment was indicated for Penelec.

The forecasts used in the evaluations of goodwill reflect operations consistent with FES' and the Companies' general business assumptions. Unanticipated changes in those assumptions could have a significant effect on future evaluations of goodwill. The impairment analysis includes a significant source of cash representing the Companies' recovery of transition costs as described in Note 9. The Companies estimate that the completion of their transition cost recovery will not result in an impairment of goodwill.

~~A summary of the changes in FES' and the Companies' goodwill for the three years ended December 31, 2007 is shown below.~~

Goodwill FES CEI TE JCP&L Met-Ed Penelec
(In millions)
Balance as of January 1, 2005
$ 26 $ 1,694 $ 505 $ 1,998 $ 870 $ 888
Non-core sset sales (2 ) - - - - -
Adjustments related to GPU acquisition
(12 ) (6 ) (6 )
Adjustments related to Centerior acquisition
(5 ) (4 )
Balance as of December 31, 2005
24 1,689 501 1,986 864 882
Impairment charges
(355 )
Adjustments related to Centerior acquisition

Adjustments related to GPU acquisition
(24 ) (13 ) (21 )
Balance as of December 31, 2006
24 1,689 501 1,962 496 861
Adjustments related to GPU acquisition
(136 ) (72 ) (83 )
Balance as of December 31, 2007
$ 24 $ 1,689 $ 501 $ 1,826 $ 424 $ 778

~~Investments~~

At the end of each reporting period, FES and the Companies evaluate their investments for impairment. In accordance with SFAS 115 and FSP SFAS 115-1 and SFAS 124-1, investments classified as available-for-sale securities are evaluated to determine whether a decline in fair value below the cost basis is other-than-temporary. FES and the Companies first consider their intent and ability to hold the investment until recovery and then consider, among other factors, the duration and the extent to which the security's fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. If the decline in fair value is determined to be other-than-temporary, the cost basis of the investment is written down to fair value. Upon adoption of FSP SFAS 115-1 and SFAS 124-1, FES, OE and TE began recognizing in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of other-than-temporary impairment. The fair value and unrealized gains and losses of FES' and the Companies' investments are disclosed in Note 5.

~~(F) COMPREHENSIVE INCOME~~

Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with stockholders and from the adoption of SFAS 158. Accumulated other comprehensive income (loss), net of tax, included on FES' and the Companies' Consolidated Balance Sheets as of December 31, 2007 and 2006 is comprised of the following components:

Accumulated Other Comprehensive Income (Loss) FES OE CEI TE JCP&L Met-Ed
Penelec

(In millions)
Net liability for unfunded retirement benefits
including the implementation of SFAS 158
$ (4 ) $ (9 ) $ (104 ) $ (42 ) $ (42 ) $ (25 ) $ (7 )
Unrealized gain on investments 126 12 - 5 - - -
Unrealized gain (loss) on derivative hedges (10 ) - - - (2 ) (1 ) -
AOCI (AOCL) Balance, December 31, 2006 $ 112 $ 3 $ (104 ) $ (37 ) $ (44 ) $ (26 ) $ (7 )

Net liability for unfunded retirement benefits
including the implementation of SFAS 158
$ (11 ) $ 32 $ (69 ) $ (18 ) $ (18 ) $ (14 ) $ 5
Unrealized gain on investments 168 16 - 7 - - -
Unrealized gain (loss) on derivative hedges (16 ) - - - (2 ) (1 ) -
AOCI (AOCL) Balance, December 31, 2007 $ 141 $ 48 $ (69 ) $ (11 ) $ (20 ) $ (15 ) $ 5

~~Other comprehensive income (loss) reclassified to net income in the three years ended December 31, 2007 is as follows:~~

2007 FES OE CEI TE JCP&L Met-Ed Penelec
(In millions)
Pension and other postretirement
     benefits
$ (5 ) $ (14 ) $ 5 $ 2 $ (8 ) $ (6 ) $ (11 )
Loss on investments (13 ) (3 ) - - - - -
Loss on derivative hedges (12 ) - - - - - -
    Reclassification to net income (30 ) (17 ) 5 2 (8 ) (6 ) (11 )
Income taxes (benefits) related to
    reclassification to net income
(13 ) (6 ) 2 1 (4 ) (3 ) (5 )
Reclassification to net income, net of
     income taxes (benefits)
$ (17 ) $ (11 ) $ 3 $ 1 $ (4 ) $ (3 ) $ (6 )

2006
Gain (Loss) on investments $ 28 $ - $ - $ (1 ) $ - $ - $ -
Loss on derivative hedges (9 ) - - - - - -
    Reclassification to net income 19 - - (1 ) - - -
Income taxes related to
    reclassification to net income
7 - - - - - -
Reclassification to net income, net of
     income taxes
$ 12 $ - $ - $ (1 ) $ - $ - $ -

2005
Gain on investments $ 1 $ 18 $ 28 $ 20 $ - $ - $ -
Gain on derivative hedges 3 - - - - - -
    Reclassification to net income 4 18 28 20 - - -
Income taxes related to
    reclassification to net income
2 7 11 8 - - -
Reclassification to net income, net of
     income taxes
$ 2 $ 11 $ 17 $ 12 $ - $ - $ -

~~(G) CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE~~

Results in 2005 included after-tax charges of $8.8 million for FES, $16.3 million for OE, $3.7 million for CEI, $0.3 million for Met-Ed and $0.8 million for Penelec recorded as the cumulative effect of a change in accounting principle upon the adoption of FIN 47 in December 2005. Applicable legal obligations as defined under FIN 47 were identified at FES' active and retired generating units and the Companies' substation control rooms, service center buildings, line shops and office buildings, with asbestos remediation recognized as the primary conditional ARO. See Note 11 for further discussion of FES' and the Companies' asset retirement obligations.

~~(H) DIVESTITURES AND DISCONTINUED OPERATIONS~~

On October 1, 2007, Met-Ed sold 100% of its interest in York Haven Power Company for $5 million. The sale was subject to regulatory accounting and did not have a material impact on Met-Ed's earnings.

On March 31, 2005, FES completed the sale of its retail natural gas business for an after-tax gain of $5 million. The net results of $5 million (including the gain on the sale of assets) associated with the divested business are reported as discontinued operations on its Consolidated Statements of Income for 2005. Revenues and pre-tax operating results associated with discontinued operations in 2005 were $146 million and $1 million, respectively.

~~3. TRANSACTIONS WITH AFFILIATED COMPANIES~~

FES' and the Companies' operating revenues, operating expenses, investment income and interest expense include transactions with affiliated companies. These affiliated company transactions include PSAs between FES and the Companies, support service billings from FESC, FENOC and interest on associated company notes. In the fourth quarter of 2005, the Ohio Companies and Penn completed the intra-system transfers of their non-nuclear and nuclear generation assets to FGCO and NGC, respectively, excluding the leasehold interests of the Ohio Companies in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliated entities (see Note 14). This resulted in the elimination of the fossil generating units lease arrangement and the nuclear generation PSA between FES and the Ohio Companies with the exception of those arrangements related to the leasehold interests not included in the transfer. The Ohio Companies continue to have a PSA with FES to meet their PLR and default service obligations. Met-Ed and Penelec also have a partial requirements PSA with FES to meet a portion of their PLR and default service obligations (see Note 9(C)). FES was a supplier to JCP&L as a result of the BGS auction process through May 31, 2006. FES is incurring interest expense through FGCO and NGC on associated company notes payable to the Ohio Companies and Penn related to the intra-system generation asset transfers. The primary affiliated company transactions for FES and the Companies for the three years ended December 31, 2007 are as follows:

Affiliated Company Transactions - 2007 FES OE CEI TE JCP&L Met-Ed
Penelec

(In millions)
Revenues:
Electric sales to affiliates
$ 2,901 $ 73 $ 92 $ 167 $ - $ - $ -
Ground lease with ATSI - 12 7 2 - - -

Expenses:

Purchased power from affiliates
234 1,261 770 392 - 290 285
Support services
560 146 70 55 100 54 58

Investment Income:

Interest income from affiliates
- 30 17 18 1 1 1
Interest income from FirstEnergy
28 29 2 - - - -

Interest Expense:

Interest expense to affiliates
31 1 1 - 1 1 1
Interest expense to FirstEnergy
34 - 1 10 11 10 11

Affiliated Company Transactions - 2006 FES OE CEI TE JCP&L Met-Ed
Penelec

(In millions)
Revenues:
Electric sales to affiliates
$ 2,609 $ 80 $ 95 $ 170 $ 14 $ - $ -
Ground lease with ATSI - 12 7 2 - - -

Expenses:

Purchased power from affiliates
257 1,264 727 363 25 178 154
Support services
602 143 63 63 93 51 55

Investment Income:

Interest income from affiliates
- 75 58 32 1 1 1
Interest income from FirstEnergy
12 25 - - - - -

Interest Expense:

Interest expense to affiliates
109 - - - - - -
Interest expense to FirstEnergy
53 - 7 7 11 5 11

Affiliated Company Transactions - 2005 FES OE CEI TE JCP&L Met-Ed
Penelec

(In millions)
Revenues:
Electric sales to affiliates
$ 2,425 $ 355 $ 362 $ 300 $ 33 $ - $ -
Generating units rent from FES - 146 49 12 - - -
Ground lease with ATSI - 12 7 2 - - -

Expenses:

Purchased power from affiliates
308 938 557 295 78 348 321
Support services
64 314 257 171 94 45 51

Investment Income:

Interest income from affiliates
- 25 7 22 - - -
Interest income from FirstEnergy
- 22 - - - - -

Interest Expense:

Interest expense to affiliates
129 - - - - - -
Interest expense to FirstEnergy
55 1 - 11 4 2 4

FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to FES and the Companies from FESC and FENOC subsidiaries of FirstEnergy. The majority of costs are directly billed or assigned at no more than cost. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC and FENOC. The current allocation or assignment formulas used and their bases include multiple factor formulas: each company's proportionate amount of FirstEnergy's aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Management believes that these allocation methods are reasonable. Intercompany transactions with FirstEnergy and its other subsidiaries are generally settled under commercial terms within thirty days.

In the three years ended December 31, 2007, TE sold 150 MW of its Beaver Valley Unit 2 leased capacity entitlement to CEI ($98 million in 2007, $102 million in 2006 and $105 million in 2005). This sale agreement was terminated at the end of 2007.

~~4. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS~~

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees and non-qualified plans that cover certain 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. On January 2, 2007, FirstEnergy made a $300 million voluntary cash contribution to its qualified pension plan. Projections indicated that additional cash contributions will not be required before 2017.

FirstEnergy 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 also available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FES and the Companies recognize the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. During 2006, FirstEnergy amended the OPEB plan effective in 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized healthcare coverage. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement for disability related benefits.

Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans and earnings on plan assets. Such factors may be further affected by business combinations which impact employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of December 31, 2007.

In December 2006, FirstEnergy adopted SFAS 158. This Statement requires employers to recognize an asset or liability for the overfunded or underfunded status of their pension and other postretirement benefit plans. For a pension plan, the asset or liability is the difference between the fair value of the plan's assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan's assets and the accumulated postretirement benefit obligation. The Statement required employers to recognize all unrecognized prior service costs and credits and unrecognized actuarial gains and losses in AOCL, net of tax. Such amounts will be adjusted as they are subsequently recognized as components of net periodic benefit cost or income pursuant to the current recognition and amortization provisions. The incremental impact of adopting SFAS 158 was a decrease of $1.0 billion in pension assets, a decrease of $383 million in pension liabilities and a decrease in AOCL of $327 million, net of tax.

Obligations and Funded Status Pension Benefits Other Benefits
As of December 31
2007 2006 2007 2006
(In millions)
Change in benefit obligation
Benefit obligation as of January 1
$ 5,031 $ 4,911 $ 1,201 $ 1,884
Service cost
88 87 21 34
Interest cost
294 276 69 105
Plan participants' contributions
- - 23 20
Plan amendments
- - - (620 )
Medicare retiree drug subsidy
- - - 6
Actuarial (gain) loss
(381 ) 38 (30 ) (119 )
Benefits paid
(282 ) (281 ) (102 ) (109 )
Benefit obligation as of December 31
$ 4,750 $ 5,031 $ 1,182 $ 1,201

Change in fair value of plan assets

Fair value of plan assets as of January 1
$ 4,818 $ 4,525 $ 607 $ 573
Actual return on plan assets
438 567 43 69
Company contribution
311 7 47 54
Plan participants' contribution
- - 23 20
Benefits paid
(282 ) (281 ) (102 ) (109 )
Fair value of plan assets as of December 31
$ 5,285 $ 4,818 $ 618 $ 607

Qualified plan $ 700 $ (43 )
Non qualified plans (165 ) (170 )
Funded status
$ 535 $ (213 ) $ (564 ) $ (594 )

Accumulated benefit obligation $ 4,397 $ 4,585

Amounts Recognized in the Statement of

Financial Position

Noncurrent assets
$ 700 $ - $ - $ -
Current liabilities
(7 ) (7 ) - -
Noncurrent liabilities
(158 ) (206 ) (564 ) (594 )
Net asset (liability) as of December 31
$ 535 $ (213 )) $ (564 ) $ (594 )

Amounts Recognized in

Accumulated Other Comprehensive Income

Prior service cost (credit)
$ 83 $ 97 $ (1,041 ) $ (1,190 )
Actuarial loss
623 1,039 635 702
Net amount recognized
$ 706 $ 1,136 $ (406 ) $ (488 )

Assumptions Used to Determine

Benefit Obligations As of December 31

Discount rate
6.50 % 6.00 % 6.50 % 6.00 %
Rate of compensation increase
5.20 % 3.50 %

Allocation of Plan Assets

As of December 31

Asset Category

Equity securities
61 % 64 % 69 % 72 %
Debt securities
30 29 27 26
Real estate
7 5 2 1
Private equities
1 1 - -
Cash
1 1 2 1
Total
100 % 100 % 100 % 100 %

~~FES' and the Companies' share of the net pension and OPEB asset (liability) as of December 31, 2007 and 2006 is as follows:~~

Pension Benefits Other Benefits
Net Pension and OPEB Asset (Liability)
2007 2006 2007 2006
(In millions)
FES
$ 42 $ (157 ) $ (102 ) $ (81 )
OE
229 68 (178 ) (167 )
CEI
62 (13 ) (93 ) (110 )
TE
29 (3 ) (63 ) (74 )
JCP&L
93 15 8 (8 )
Met-Ed
51 7 (8 ) (19 )
Penelec
66 11 (40 ) (49 )

Estimated Items to be Amortized in 2008
Net Periodic Pension Cost from Pension Other
Accumulated Other Comprehensive Income Benefits Benefits
(In millions)
Prior service cost (credit) $ 13 $ (149 )
Actuarial loss $ 8 $ 47

Pension Benefits Other Benefits
Components of Net Periodic Benefit Costs 2007 2006 2005 2007 2006 2005
(In millions)
Service cost $ 88 $ 87 $ 80 $ 21 $ 34 $ 40
Interest cost 294 276 262 69 105 111
Expected return on plan assets (449 ) (396 ) (345 ) (50 ) (46 ) (45 )
Amortization of prior service cost 13 13 10 (149 ) (76 ) (45 )
Recognized net actuarial loss 45 62 39 45 56 40
Net periodic cost $ (9 ) $ 42 $ 46 $ (64 ) $ 73 $ 101

Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost Pension Benefits Other Benefits
for Years Ended December 31 2007 2006 2005 2007 2006 2005
Discount rate 6.00 % 5.75 % 6.00 % 6.00 % 5.75 % 6.00 %
Expected long-term return on plan assets 9.00 % 9.00 % 9.00 % 9.00 % 9.00 % 9.00 %
Rate of compensation increase 3.50 % 3.50 % 3.50 %

~~FES' and the Companies' share of the net periodic pension and OPEB cost for the three years ended December 31, 2007 is as follows:~~

Pension Benefits Other Benefits
Net Periodic Pension and OPEB Costs 2007 2006 2005 2007 2006 2005
(In millions)
FES
$ 21 $ 40 $ 33 $ (10 ) $ 14 $ 23
OE
(16 ) (6 ) 0 (11 ) 17 28
CEI
1 4 1 4 11 15
TE
- 1 1 5 8 9
JCP&L
(9 ) (5 ) (1 ) (16 ) 2 7
Met-Ed
(7 ) (7 ) (4 ) (10 ) 3 1
Penelec
(10 ) (5 ) (5 ) (13 ) 7 8

In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. The assumed rates of return on pension plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy's pension trusts. The long-term rate of return is developed considering the portfolio's asset allocation strategy.

FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

FES and the Companies have assessed the impact of recent market developments, including a series of rating agency downgrades of subprime mortgage-related assets, on the value of the assets held in their pension and other postretirement benefit trusts. Based on this assessment, FES and the Companies believe that the fair value of their investments as of December 31, 2007 will not be materially affected by the subprime credit crisis due to their relatively small exposure to subprime assets.

Assumed Health Care Cost Trend Rates
As of December 31
2007 2006
Health care cost trend rate assumed for next

year (pre/post-Medicare)
9-11 % 9-11 %
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate) 5 % 5 %
Year that the rate reaches the ultimate trend

rate (pre/post-Medicare)
2015-2017 2011-2013

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

1-Percentage- 1-Percentage-
Point Increase Point Decrease
(In millions)
Effect on total of service and interest cost
$ 5 $ (4 )
Effect on accumulated postretirement benefit obligation
$ 48 $ (42 )

~~Taking into account estimated employee future service, FirstEnergy expects to make the following pension benefit payments from plan assets and other benefit payments, net of the Medicare subsidy:~~

Pension Other
Benefits Benefits
(In millions)
2008
$ 300 $ 83
2009
300 86
2010
307 90
2011
313 94
2012
322 95
Years 2013- 2017
1,808 495

~~5. FAIR VALUE OF FINANCIAL INSTRUMENTS~~

~~(A) LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS~~

All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value, in the caption "short-term borrowings." The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations as shown in the Consolidated Statements of Capitalization as of December 31:

2007

2006

Carrying Fair Carrying Fair

Value

Value

Value

Value

(In millions)
FES
$ 1,975 $ 1,971 $ 3,084 $ 3,084
OE
1,182 1,197 1,294 1,337
CEI
1,666 1,706 1,919 2,000
TE
304 283 389 388
JCP&L
1,597 1,560 1,366 1,388
Met-Ed
542 535 592 572
Penelec
779 779 479 490

The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FES and the Companies.

~~(B) INVESTMENTS~~

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities. FES and the Companies periodically evaluate their investments for other-than-temporary impairment. They first consider their intent and ability to hold the investment until recovery and then consider, among other factors, the duration and the extent to which the securitys fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment.

FES and the Companies have assessed the impact of recent market developments, including a series of rating agency downgrades of subprime mortgage-related assets, on the value of the assets held in their nuclear decommissioning trusts. Based on this assessment, FES and the Companies believe that the fair value of their investments as of December 31, 2007 will not be materially affected by the subprime credit crisis due to their relatively small exposure to subprime assets.

~~Available-For-Sale Securities~~

FES and the Companies hold debt and equity securities within their nuclear decommissioning trusts, nuclear fuel disposal trusts and NUG trusts. These trust investments are classified as available-for-sale with the fair value representing quoted market prices. FES and the Companies have no securities held for trading purposes.

The following table provides the carrying value, which approximates fair value, of investments in available-for-sale securities as of December 31, 2007 and 2006. The fair value was determined using the specific identification method.

2007

2006

Debt Equity Debt Equity

Securities

Securities

Securities

Securities

(In millions)
FES
$ 417 $ 916 $ 365 $ 873
OE
45 82 38 80
TE
67 - 61 -
JCP&L(1)
248 102 235 97
Met-Ed
115 172 106 164
Penelec(2)
167 83 151 72

~~(1)~~	~~Excludes $2 million and $3 million of cash in 2007 and 2006, respectively~~
~~(2)~~	~~Excludes $1 million and $2 million of cash in 2007 and 2006, respectively~~

~~The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities as of December 31:~~

2007 2006
Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair
Basis Gains Losses Value Basis Gains Losses Value
Debt securities (In millions)
FES
$ 402 $ 15 $ - $ 417 $ 360 $ 5 $ - $ 365
OE
43 2 - 45 38 - - 38
TE
63 4 - 67 61 - - 61
JCP&L
249 3 4 248 237 2 4 235
Met-Ed
112 3 - 115 105 1 - 106
Penelec
166 1 - 167 150 1 - 151

Equity securities

FES
$ 631 $ 285 $ - $ 916 $ 652 $ 221 $ - $ 873
OE
59 23 - 82 61 19 - 80
JCP&L
89 13 - 102 73 24 - 97
Met-Ed
136 36 - 172 114 50 - 164
Penelec
80 3 - 83 55 17 - 72

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income for the three years ended December 31, 2007 were as follows:

FES OE CEI TE JCP&L Met-Ed
Penelec

(In millions)
2007
Proceeds from sales
$ 656 $ 38 $ - $ 45 $ 196 $ 185 $ 175
Realized gains
29 1 - 1 23 30 19
Realized losses
42 4 - 1 3 2 1
Interest and dividend income
42 4 - 3 13 8 10

2006

Proceeds from sales
$ 1,066 $ 39 $ - $ 53 $ 217 $ 176 $ 99
Realized gains
118 1 - - 1 1 -
Realized losses
90 1 - 1 5 4 4
Interest and dividend income
36 3 - 3 13 7 7

2005

Proceeds from sales
$ 1,097 $ 284 $ 490 $ 366 $ 165 $ 167 $ 93
Realized gains
109 35 49 35 4 6 4
Realized losses
39 7 20 15 5 7 6
Interest and dividend income
32 13 12 9 13 6 7

Upon adoption of FSP SFAS 115-1 and SFAS 124-1, FES, OE and TE began expensing unrealized losses on available-for-sale securities held in its nuclear decommissioning trusts since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of other-than-temporary impairment.

Unrealized gains applicable to OE's, TE's and the majority of FES' decommissioning trusts are recognized in OCI in accordance with SFAS 115, as fluctuations in fair value will eventually impact earnings. The decommissioning trusts of JCP&L, Met-Ed and Penelec are subject to regulatory accounting in accordance with SFAS 71. Net unrealized gains and losses are recorded as regulatory assets or liabilities since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers.

The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries.

~~Held-To-Maturity Securities~~

The following table provides the amortized cost basis (carrying value), unrealized gains and losses and fair values of investments in held-to-maturity securities with maturity dates ranging from 2008 to 2017 excluding; restricted funds, whose carrying value is assumed to approximate market value, notes receivable, whose fair value represents the present value of the cash inflows based on the yield to maturity, and other investments of $87 million and $127 million in 2007 and 2006, respectively, excluded by SFAS 107, "Disclosures about Fair Values of Financial Instruments," as of December 31:

2007 2006
Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair
Basis Gains Losses Value Basis Gains Losses Value
Debt securities (In millions)
OE

254

28

-

282

291

34

-

325
CEI

463

68

-

531

523

65

-

588
JCP&L

1

-

-

1

-

-

-

-

Equity securities

OE

2

-

-

2

3

-

-

3

~~The following table provides the approximate fair value and related carrying amounts of notes receivable as of December 31:~~

2007

2006
Carrying Fair Carrying Fair

Value

Value

Value

Value
Notes receivable (In millions)
FES 65 63 69 66
OE 259 299 1,219 1,251
CEI

1

1

487

487
TE

192

223

298

327

The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. The maturity dates range from 2008 to 2040.

~~(C) DERIVATIVES~~

FES and the Companies are 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, they use 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 FES and the Companies. 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.

FES and the Companies account for derivative instruments on their Consolidated Balance Sheets at their fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet that criteria are accounted for using traditional accrual accounting. The changes in the fair value of derivative instruments that do not meet the normal purchase 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.

FES hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases. FES maximum hedge terms are typically two years. 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. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings. The ineffective portion of cash flow hedge was immaterial during this period.

FES net deferred losses of $16 million included in AOCL as of December 31, 2007, for derivative hedging activity, as compared to $10 million as of December 31, 2006, resulted from a net $14 million increase related to current hedging activity and an $8 million decrease due to net hedge losses reclassified to earnings during 2007. Based on current estimates, approximately $15 million (after tax) of the net deferred losses on derivative instruments in AOCL as of December 31, 2007 is 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.

6.	~~LEASES~~

~~FES and the Companies lease certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases.~~

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion (net after-tax proceeds of approximately $1.2 billion) for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034. A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates. The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCOs obligations under each of the leases. This transaction, which is classified as an operating lease under GAAP for FES and a financing for FGCO, generated tax capital gains of approximately $742 million, all of which were offset by existing tax capital loss carryforwards.

In 1987, OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. In that same year, CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respective leases, OE, CEI and TE continue to be responsible, to the extent of their leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. They have the right, at the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes.

Effective October 16, 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 FGCOs leasehold interests under its July 13, 2007 Bruce Mansfield Unit 1 sale and leaseback transaction, to a newly formed wholly-owned subsidiary on December 17, 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE remain primarily liable on the 1987 leases and related 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.

The rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2007 are summarized as follows:

FES OE CEI TE JCP&L Met-Ed
Penelec

(In millions)
2007
Operating leases
Interest element
$ 29.8 $ 82.8 $ 23.8 $ 38.2 $ 2.9 $ 2.1 $ 0.8
Other
14.6 62.2 37.6 62.8 5.4 1.6 3.9
Capital leases

Interest element
- 0.1 0.4 - - - -
Other
0.1 - 0.6 - - - -
Total rentals
$ 44.5 $ 145.1 $ 62.4 $ 101.0 $ 8.3 $ 3.7 $ 4.7

2006

Operating leases
Interest element
$ - $ 87.1 $ 26.3 $ 41.1 $ 2.8 $ 2.0 $ 0.6
Other
- 57.5 48.1 68.2 4.5 1.4 3.8
Capital leases

Interest element
- 0.3 0.4 - - - -
Other
- 1.3 0.6 - - - -
Total rentals
$ - $ 146.2 $ 75.4 $ 109.3 $ 7.3 $ 3.4 $ 4.4

2005

Operating leases
Interest element
$ - $ 93.4 $ 28.4 $ 43.9 $ 2.6 $ 1.9 $ 0.7
Other
- 52.3 40.9 62.3 3.2 1.0 2.1
Capital leases

Interest element
- 0.8 0.5 - - - -
Other
- 1.9 0.5 - - - -
Total rentals
$ - $ 148.4 $ 70.3 $ 106.2 $ 5.8 $ 2.9 $ 2.8

Established by OE in 1996, PNBV purchased a portion of the lease obligation bonds issued on behalf of lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. Similarly, CEI and TE established Shippingport in 1997 to purchase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions.

~~The future minimum capital lease payments as of December 31, 2007 are as follows:~~

Capital Leases FES OE CEI TE
(In millions)
2008 $ 0.1 $ 0.1 $ 1.0 $ -
2009 - 0.2 1.0 0.1
2010 0.1 0.1 1.0 -
2011 - 0.2 1.0 -
2012 - 0.1 0.6 -
Years thereafter - - - -
Total minimum lease payments 0.2 0.7 4.6 0.1
Executory costs - - - -
Net minimum lease payments 0.2 0.7 4.6 0.1
Interest portion - 0.4 0.9 -
Present value of net minimum
lease payments
0.2 0.3 3.7 0.1
Less current portion 0.1 0.1 0.6 -
Noncurrent portion $ 0.1 $ 0.2 $ 3.1 $ 0.1

~~The future minimum operating lease payments as of December 31, 2007 are as follows:~~

Operating Leases FES OE CEI TE JCP&L Met-Ed
Penelec

(In millions)
2008 $ 172.7 $ 147.8 $ 5.7 $ 64.9 $ 8.9 $ 4.2 $ 5.5
2009 175.9 148.8 6.2 65.0 9.4 4.7 5.8
2010 176.8 149.5 6.1 65.0 8.9 4.6 5.6
2011 171.8 148.5 5.8 64.9 7.9 4.2 5.1
2012 215.0 148.3 5.2 64.8 7.0 3.8 4.5
Years thereafter 2,544.6 615.8 29.6 275.2 64.3 47.1 15.0
Total minimum lease payments $ 3,456.8 $ 1,358.7 $ 58.6 $ 599.8 $ 106.4 $ 68.6 $ 41.5

CEI and TE had recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger between OE and Centerior. The total above-market lease obligation of $722 million associated with Beaver Valley Unit 2 has been amortized on a straight-line basis (approximately $31 million and $6 million per year for CEI and TE, respectively). Effective December 31, 2007, TE terminated the sale of its 150 MW of Beaver Valley Unit 2 leased capacity entitlement to CEI. The remaining above-market lease liability for Beaver Valley Unit 2 of $347 million as of December 31, 2007, of which $37 million is classified as current, will be amortized by TE on straight-line basis through the end of the lease term in 2017. The total above-market lease obligation of $755 million associated with the Bruce Mansfield Plant has been amortized on a straight-line basis (approximately $29 million and $19 million per year for CEI and TE, respectively). Effective October 16, 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. The remaining above-market lease liability for the Bruce Mansfield Plant of $399 million as of December 31, 2007, of which $46 million is classified as current, will be amortized by FGCO on straight-line basis through the end of the lease term in 2016.

7.	~~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. FES and the Companies consolidate VIEs when they are determined to be the VIE's primary beneficiary as defined by FIN 46R.

~~Trusts~~

PNBV and Shippingport were 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 OE's Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI's and TE's Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.

~~Loss Contingencies~~

FES and the Ohio Companies are exposed to losses under their applicable sale-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 companys net exposure to loss based upon the casualty value provisions mentioned above:

Maximum Exposure
Discounted
Lease Payments, net
Net Exposure
(In millions)
FES $ 1,338 $ 1,198 $ 140
OE 837 610 227
CEI 753 85 668
TE 753 449 304

Effective October 16, 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant under their 1987 sale and leaseback transactions 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 FGCOs leasehold interests under its July 13, 2007 Bruce Mansfield Unit 1 sale and leaseback transaction discussed above, to a newly formed wholly-owned subsidiary on December 17, 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE remain primarily liable on the 1987 leases and related 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.

~~Power Purchase Agreements~~

In accordance with FIN 46R, FES and the Companies evaluated their 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 FES and the Companies and the contract price for power is correlated with the plants variable costs of production. JCP&L, Met-Ed and Penelec, maintain 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. JCP&L, Met-Ed and Penelec were not involved in the creation of, and have no equity or debt invested in, these entities.

Management 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, management 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. Management has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be proprietary. As such, JCP&L, Met-Ed and Penelec applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R.

Since JCP&L, Met-Ed and Penelec have no equity or debt interests in the NUG entities, their maximum exposure to loss relates primarily to the above-market costs they incur for power. JCP&L, Met-Ed and Penelec expect any above-market costs they incur to be recovered from customers. Purchased power costs from these entities during the three years ended December 31, 2007 are shown in the following table:

2007 2006 2005
(In millions)
JCP&L $ 90 $ 81 $ 101
Met-Ed 56 60 50
Penelec 30 29 28

~~8. TAXES~~

~~Income Taxes~~

FES and the Companies record income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and loss carryforwards and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. Details of income taxes for the three years ended December 31, 2007 are shown below:

PROVISION FOR INCOME TAXES FES OE CEI TE JCP&L Met-Ed Penelec
(In millions)
2007
Currently payable-
Federal $ 528 $ 105 $ 166 $ 73 $ 138 $ 26 $ 41
State 111 (4 ) 20 7 42 7 12
639 101 186 80 180 33 53
Deferred, net-
Federal (288 ) - (23 ) (27 ) (25 ) 30 10
State (42 ) 4 2 2 (5 ) 6 1
(330 ) 4 (21 ) (25 ) (30 ) 36 11
Investment tax credit amortization (4 ) (4 ) (2 ) (1 ) (1 ) (1 ) -
Total provision for income taxes $ 305 $ 101 $ 163 $ 54 $ 149 $ 68 $ 64

2006
Currently payable-
Federal $ 102 $ 162 $ 174 $ 83 $ 79 $ 21 $ 21
State 18 30 32 14 24 6 7
120 192 206 97 103 27 28
Deferred, net-
Federal 110 (58 ) (14 ) (35 ) 34 40 26
State 11 (7 ) 1 (1 ) 11 11 3
121 (65 ) (13 ) (36 ) 45 51 29
Investment tax credit amortization (5 ) (4 ) (4 ) (1 ) (1 ) (1 ) -
Total provision for income taxes $ 236 $ 123 $ 189 $ 60 $ 147 $ 77 $ 57

2005
Currently payable-
Federal $ 29 $ 275 $ 90 $ 62 $ 78 $ 24 $ 7
State 1 74 23 18 22 8 1
30 349 113 80 100 32 8
Deferred, net-
Federal 94 (60 ) 28 (19 ) 27 2 11
State 5 37 17 15 10 (3 ) (1 )
99 (23 ) 45 (4 ) 37 (1 ) 10
Investment tax credit amortization (5 ) (16 ) (5 ) (2 ) (1 ) (1 ) (1 )
Total provision for income taxes $ 124 $ 310 $ 153 $ 74 $ 136 $ 30 $ 17

FES and the Companies are all party to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, is reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit.

The following tables provide a reconciliation of federal income tax expense at FES and the Companies statutory rate to their total provision for income taxes for the three years ended December 31, 2007.

FES OE CEI TE JCP&L Met-Ed Penelec
(In millions)
2007
Book income before provision for income taxes $ 833 $ 298 $ 440 $ 145 $ 335 $ 164 $ 157
Federal income tax expense at statutory rate $ 292 $ 104 $ 154 $ 51 $ 117 $ 57 $ 55
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits (4 ) (4 ) (2 ) (1 ) (1 ) (1 ) -
State income taxes, net of federal tax benefit 45 - 14 6 24 9 8
Manufacturing deduction (6 ) (2 ) (1 ) - - - -
Other, net (22 ) 3 (2 ) (2 ) 9 3 1
Total provision for income taxes $ 305 $ 101 $ 163 $ 54 $ 149 $ 68 $ 64

2006
Book income before provision for income taxes $ 655 $ 335 $ 495 $ 159 $ 337 $ (163 ) $ 141
Federal income tax expense at statutory rate $ 229 $ 117 $ 173 $ 56 $ 118 $ (57 ) $ 49
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits (5 ) (4 ) (4 ) (1 ) (1 ) (1 ) -
State income taxes, net of federal tax benefit 18 15 22 8 23 11 6
Goodwill impairment - - - - - 124 -
Other, net (6 ) (5 ) (2 ) (3 ) 7 - 2
Total provision for income taxes $ 236 $ 123 $ 189 $ 60 $ 147 $ 77 $ 57

2005
Book income before provision for income taxes $ 333 $ 640 $ 384 $ 150 $ 319 $ 76 $ 44
Federal income tax expense at statutory rate $ 117 $ 224 $ 134 $ 52 $ 112 $ 27 $ 16
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits (5 ) (16 ) (5 ) (2 ) (1 ) (1 ) (1 )
State income taxes, net of federal tax benefit 4 72 26 22 21 3 -
Penalties 10 3 - - - - -
Other, net (2 ) 27 (2 ) 2 4 1 2
Total provision for income taxes $ 124 $ 310 $ 153 $ 74 $ 136 $ 30 $ 17

~~Accumulated deferred income taxes as of December 31, 2007 and 2006 are as follows:~~

ACCUMULATED DEFERRED INCOME TAXES FES OE CEI TE JCP&L Met-Ed Penelec
(In millions)

AS OF DECEMBER 31, 2007
Property basis differences $ 281 $ 463 $ 372 $ 154 $ 439 $ 266 $ 319
Regulatory transition charge - 139 156 116 235 60 -
Customer receivables for future income taxes - 22 1 - 14 49 62
Deferred customer shopping incentive - 61 172 29 - - -
Deferred sale and leaseback gain (455 ) (49 ) - - (20 ) (11 ) -
Nonutility generation costs - - - - - 22 (112 )
Unamortized investment tax credits (23 ) (6 ) (7 ) (4 ) (2 ) (6 ) (5 )
Other comprehensive income 84 25 (39 ) (8 ) (20 ) (16 ) (2 )
Retirement benefits (13 ) (14 ) 25 (1 ) 39 16 (17 )
Lease market valuation liability (148 ) - - (135 ) - - -
Oyster Creek securitization (Note 10(C)) - - - - 149 - -
Asset retirement obligations 34 (2 ) (3 ) 7 (48 ) (57 ) (64 )
Deferred gain for asset sales - affiliated companies - 45 30 10 - - -
Allowance for equity funds used during construction - 21 - - - - -
PJM transmission costs - - - - - 97 13
All other (37 ) 76 19 (65 ) 14 19 17
Net deferred income tax liability (asset) $ (277 ) $ 781 $ 726 $ 103 $ 800 $ 439 $ 211

AS OF DECEMBER 31, 2006
Property basis differences $ 112 $ 497 $ 534 $ 243 $ 436 $ 277 $ 329
Regulatory transition charge - (28 ) 116 33 254 82 -
Customer receivables for future income taxes - 31 3 (3 ) 4 44 62
Deferred customer shopping incentive - 68 132 18 - - -
Deferred sale and leaseback gain - (55 ) - - (20 ) (11 ) -
Nonutility generation costs - - - - - 1 (123 )
Unamortized investment tax credits (24 ) (8 ) (9 ) (3 ) (3 ) (7 ) (5 )
Other comprehensive income 60 (15 ) (70 ) (24 ) (44 ) (28 ) (18 )
Retirement benefits (28 ) 30 11 8 36 12 (19 )
Lease market valuation liability - - (235 ) (96 ) - - -
Oyster Creek securitization (Note 10(C)) - - - - 162 - -
Asset retirement obligations 29 10 2 4 (16 ) (42 ) (59 )
Deferred gain for asset sales - affiliated companies - 47 31 10 - - -
Allowance for equity funds used during construction - 23 - - - - -
PJM transmission costs - - - - - 53 13
All other (28 ) 74 (44 ) (29 ) (5 ) 6 14
Net deferred income tax liability $ 121 $ 674 $ 471 $ 161 $ 804 $ 387 $ 194

On January 1, 2007, FES and the Companies adopted FIN 48, which provides guidance for accounting for uncertainty in income taxes in a companys financial statements in accordance with SFAS 109. This interpretation prescribes a financial statement recognition threshold and measurement attribute for tax positions taken or expected to be taken on a companys 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 (see table below for amounts included for FES and the Companies). FirstEnergy recorded a $2.7 million (OE - $0.6 million, CEI - $0.2 million, FES - $0.5 million and other subsidiaries of FirstEnergy - $1.4 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 upon recognition. The majority of items that would not have affected the effective tax rate resulted from purchase accounting adjustments that would reduce goodwill upon recognition through December 31, 2008.

~~A reconciliation of the change in the unrecognized tax benefits for the year ended December 31, 2007 is as follows:~~

FES OE CEI TE JCP&L Met-Ed Penelec
(In millions)
Balance as of January 1, 2007
$ 14 $ (19 ) $ (15 ) $ (3 ) $ 44 $ 18 $ 20
Increase for tax positions related to the
   current year
- 1 - - - - -
Increase for tax positions related to
   prior years
4 10 2 2 - 6 -
Decrease for tax positions of
   prior years
(4 ) (4 ) (4 ) - (6 ) - (4 )
Balance as of December 31, 2007
$ 14 $ (12 ) $ (17 ) $ (1 ) $ 38 $ 24 $ 16

As of December 31, 2007, FES and the Companies expect that $7 million of the unrecognized benefits will be resolved within the next twelve months and are included in the caption Accrued taxes, with the remaining amount included in Other assets and Other non-current liabilities on the Consolidated Balance Sheets as follows:

Balance Sheet Classifications FES OE CEI TE JCP&L Met-Ed Penelec
(In millions)
Current-

   Accrued taxes
$ 3 $ 4 $ - $ - $ - $ - $ -

Non-Current-

   Other asset
(16 ) (17 ) (1 )
   Other non-current liabilities
11 - - - 38 24 16
      Net liabilities (assets)
$ 14 $ (12 ) $ (17 ) $ (1 ) $ 38 $ 24 $ 16

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. FES and the Companies include net interest and penalties in the provision for income taxes, consistent with their policy prior to implementing FIN 48.

The following table summarizes the net interest expense (income) recognized by FES and the Companies for the three years ended December 31, 2007 and the cumulative net interest payable (receivable) as of December 31, 2007 and 2006:

Net Interest Expense (Income) Net Interest Payable
For the Years Ended (Receivable)
December 31, As of December 31,
2007 2006 2005 2007 2006
(In millions) (In millions)
FES
$ - $ 1 $ - $ 2 $ 3
OE
1 1 (8 ) (5 ) (6 )
CEI
(1 ) 1 (3 ) (2 ) (3 )
TE
- 1 (1 ) - -
JCP&L
1 (2 ) 5 10 9
Met-Ed
2 - 2 5 3
Penelec
- (1 ) 3 4 4

FES and the Companies have 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 2001-2006. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audit for years 2004 and 2005 began in June 2006 and are not expected to close before December 2008. The IRS began auditing the year 2006 in April 2006 and the year 2007 in February 2007 under its Compliance Assurance Process experimental program. Neither audits are 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 FES or the Companies financial condition or results of operations.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity (see Note 6). This transaction generated tax capital gains of approximately $742 million, all of which were offset by existing tax capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowance in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 2(E)).

~~FES, Met-Ed and Penelec have pre-tax net operating loss carryforwards for state and local income tax purposes. These losses expire as follows:~~

Expiration Period
FES Met-Ed Penelec
(In millions)
2008-2012 $ - $ - $ -
2013-2017 - - -
2018-2022 22 5 229
2023-2027 16 - 14
$ 38 $ 5 $ 243

~~General Taxes~~

~~Details of general taxes for the three years ended December 31, 2007 are shown below:~~

GENERAL TAXES FES OE CEI TE JCP&L Met-Ed Penelec
(In millions)
2007
Kilowatt-hour excise $ 1 $ 99 $ 69 $ 29 $ 52 $ - $ -
State gross receipts 18 17 - - - 73 66
Real and personal property 53 59 65 19 5 2 2
Social security and unemployment 14 8 6 3 9 5 5
Other 1 (2 ) 2 - - - 3
Total general taxes $ 87 $ 181 $ 142 $ 51 $ 66 $ 80 $ 76

2006
Kilowatt-hour excise $ - $ 95 $ 68 $ 28 $ 50 $ - $ -
State gross receipts 10 19 - - - 67 62
Real and personal property 49 55 61 20 5 2 1
Social security and unemployment 13 7 5 2 9 4 5
Other 1 4 1 1 - 4 5
Total general taxes $ 73 $ 180 $ 135 $ 51 $ 64 $ 77 $ 73

2005
Kilowatt-hour excise $ - $ 94 $ 69 $ 29 $ 52 $ - $ -
State gross receipts 9 20 - - - 63 58
Real and personal property 44 67 78 25 5 2 1
Social security and unemployment 12 8 5 2 8 4 5
Other 2 4 1 1 - 5 5
Total general taxes $ 67 $ 193 $ 153 $ 57 $ 65 $ 74 $ 69

~~Commercial Activity Tax~~

On June 30, 2005, tax legislation was enacted in the State of Ohio that created a new CAT tax, which is based on qualifying taxable gross receipts and does not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax was effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and the personal property tax is phased-out over a four-year period at a rate of approximately 25% annually, beginning with the year ended 2005. During the phase-out period the Ohio income-based franchise tax was or will be computed consistent with the prior tax law, except that the tax liability as computed was multiplied by 80% in 2005; 60% in 2006; 40% in 2007 and 20% in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that were not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005.

~~The increase (decrease) to income taxes associated with the adjustment to net deferred taxes in 2005 is summarized below (in millions):~~

~~FES~~	~~$ (7~~	)
OE	~~$32~~
~~CEI~~	~~$ 4~~
TE	~~$18~~

~~Income tax expenses were reduced during 2005 by the initial phase-out of the Ohio income-based franchise tax and phase-in of the CAT tax as summarized below (in millions):~~

~~FES~~	$1
OE	$3
~~CEI~~	$5
TE	$1

~~9. REGULATORY MATTERS~~

~~(A) RELIABILITY INITIATIVES~~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 ~~(PUCO,~~(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. ~~Subsequently,~~ FirstEnergy ~~has worked systematically to complete all~~is also proceeding with the implementation of the ~~enhancements~~recommendations that were ~~identified for completion after~~to be completed subsequent to 2004 and ~~FirstEnergy expects~~will continue to ~~complete this work prior~~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 ~~the summer of 2008.~~require, substantial investment in new or material upgrades to existing equipment. The FERC ~~and the~~or other ~~affected~~applicable government agencies and reliability ~~entities~~coordinators may, ~~review FirstEnergy's work and, on the basis of any such review,~~however, take a different view as to recommended enhancements or may recommend additional enhancements in the future ~~which~~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 consultants recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation incorporates the consultants 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 consultants 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~~Utilities and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including ~~the ReliabiltyFirst~~ReliabilityFirst Corporation. All of ~~FirstEnergy's~~FirstEnergy’s facilities are located within the ~~ReliabiltyFirst~~ReliabilityFirst region. FirstEnergy actively participates in the NERC and ~~ReliabiltyFirst~~ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.

FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that the NERC, ~~ReliabiltyFirst~~ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on ~~FirstEnergy's~~FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties and thus have a material adverse effect on its financial condition, results of operations and cash flows.

In April 2007, ~~ReliabilityFirst~~ReliabilityFirst performed a routine compliance audit of ~~FirstEnergy's~~FirstEnergy’s bulk-power system within the Midwest ISO region and found it to be in full compliance with all audited reliability standards. Similarly, ~~ReliabilityFirst~~ ~~has scheduled~~in October 2008, ReliabilityFirst performed a routine compliance audit of ~~FirstEnergy's~~FirstEnergy’s bulk-power system within the PJM region and a final report is expected in ~~2008.~~early 2009. FirstEnergy ~~currently~~ does not expect any material adverse financial impact as a result of these audits.

~~(B) OHIO~~

On September 9, 2005, the Ohio Companies filed their RCP with the PUCO. The filing included a stipulation and supplemental stipulation with several parties agreeing to the provisions set forth in the plan. PUCO Rate Matters

On January 4, 2006, the PUCO issued an order which approved the stipulations clarifying certain provisions. Several parties subsequently filed appeals to the Supreme Court of Ohio in connection with certain portions of the approved RCP. In its order, the PUCO authorizedauthorizing 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 ~~25-year~~twenty-five-year period through distribution rates, which are expected to be effective on January 1, 2009 for OE and TE, and approximately May 2009 for CEI. Through December 31, 2007, the deferred fuel costs, including interest, were $111 million, $76 million and $33 million for OE, CEI and TE, respectively.

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“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 because fuel costs are a component of generation service, not distribution service,~~expenses” and ~~permitting recovery of deferred fuel costs through distribution rates constituted an impermissible subsidy. The Court~~ remanded the matter to the PUCO for further ~~consideration consistent with the Courts Opinion on this issue and affirmed the PUCO's order in all other respects.~~consideration. On September 10, 2007, the Ohio Companies filed an ~~Application~~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. ~~The Ohio Companies requested the riders to become effective in October 2007 and end in December 2008, subject to reconciliation that would be expected to continue through the first quarter of 2009.~~ On January 9, 2008, the PUCO approved the Ohio ~~Companies~~Companies’ proposed fuel cost rider to recover increased fuel costs ~~to be~~ incurred ~~commencing January 1, 2008 through December 31,~~during 2008, which ~~is expected to be~~was approximately ~~$167~~$185 million. ~~The fuel cost rider became effective January 11, 2008 and will be adjusted and reconciled quarterly.~~ 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 ~~$220~~$226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel ~~rider, with alternative options~~rider. Recovery of the deferred fuel costs was also addressed in the Ohio Companies’ comprehensive ESP filing, which was subsequently withdrawn on December 22, 2008, and also as a part of the stipulation and recommendation which was attached to the amended application for ~~the recovery period ranging from five to twenty-five years. This second application is currently pending before the PUCO.~~an ESP, both as described below.

The Ohio Companies recover all MISO transmission and ancillary service related costs incurred through a reconcilable rider that is updated annually on July 1. The riders that became effective on July 1,On June 7, 2007, ~~represent an increase over~~ the amounts collected through the 2006 riders of approximately $64 million annually (OE - $28 million, CEI - $22 million and TE - $14 million). If it is subsequently determined by the PUCO that adjustments to the riders as filed are necessary, such adjustments, with carrying costs, will be incorporated into the 2008 transmission rider filing.

~~The~~ Ohio Companies filed an application ~~and rate request~~ for an increase in electric distribution rates with the PUCO ~~on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect~~ and, would result in lowering the overall non-generation portion of the average electric bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies last distribution rate proceedings, increases in operation and maintenance expenses and recovery of regulatory assets that were authorized in prior cases. Onon August 6, 2007, ~~the Ohio Companies~~ updated their filing ~~supporting~~to support a distribution rate increase of $332 ~~million (OE - $156 million, CEI - $108 million and TE - $68 million).~~million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of ~~their~~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, ~~(OE - $57 million to $66 million, CEI - $54 million to $61 million and TE - $50 million to $53 million),~~ with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. This amount excludes the recovery of deferred fuel costs, whose recovery is now being sought in a separate proceeding before the PUCO, discussed above. 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 2008. During the evidentiary hearings and filing of briefs, the PUCO Staff ~~submitted testimony decreasing~~decreased their recommended revenue increase to a range of ~~$114~~$117 million to ~~$132~~$135 million. ~~Additionally, in testimony submitted on February 11, 2008,~~On January 21, 2009, the PUCO ~~Staff adopted a position regarding interest deferred pursuant~~granted the Ohio Companies’ application to ~~the RCP that, if upheld~~increase electric distribution rates by ~~the PUCO, would result in the write-off of approximately $13~~$136.6 million (OE - $6$68.9 million, CEI - $5$29.2 million and TE - $2$38.5 million). These increases went into effect for OE and TE on January 23, 2009, and will go into effect for CEI on May 1, 2009. Applications for rehearing of ~~interest~~this order were filed by the Ohio Companies and one other party on February 20, 2009.

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, which must contain a proposal for the supply and pricing of retail generation. A utility may also file an MRO with the PUCO, in which it would have to prove the following objective market criteria: 1) 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; 2) 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 3) 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 filing outlined 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. If the Ohio Companies proceed with the MRO option, successful bidders (including affiliates) would be required to post independent credit requirements and could be subject to significant collateral calls depending upon power price movement. The PUCO denied the MRO application on November 26, 2008. The Ohio Companies filed an application for rehearing on December 23, 2008, which the PUCO granted on January 21, 2009, for the purpose of further consideration of the matter.

The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred ~~through~~in 2006 and 2007, and the distribution rate request described above. On December 19, 2008, the PUCO significantly modified and approved the ESP as modified. On December 22, 2008, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application as allowed by the terms of SB221. The Ohio Companies further notified the PUCO that, pursuant to SB221, the Ohio Companies would continue their current rate plan in effect and filed tariffs to continue those rates.

On December 31, ~~2007.~~2008, the Ohio Companies conducted a CBP, using an RFP format administered by an independent third party, for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. Four qualified wholesale bidders were selected, including FES, for 97% of the tranches offered in the RFP. The average winning bid price was equivalent to a retail rate of 6.98 cents per kilowatt-hour. Subsequent to the RFP, the remaining 3% of the Ohio Companies’ wholesale energy and capacity needs were obtained through a bilateral contract with the lowest bidder in the RFP procurement. The power supply obtained through the foregoing processes provides generation service to the Ohio Companies’ retail customers who choose not to shop with alternative suppliers.

Following comments by other parties on the Ohio Companies’ December 22, 2008, filing which continued the current rate plan, the PUCO ~~is expected~~issued an Order on January 7, 2009, that prevented OE and TE from collecting RTC and discontinued the collection of two fuel riders for the Ohio Companies. The Ohio Companies filed an application for rehearing on January 9, 2009, and also filed an application for a new fuel rider to ~~render its decision during~~recover the ~~second or third quarter of 2008. The new rates would become effective~~increased costs for purchasing power during the period January 1, 2009 through March 31, 2009. On January 14, 2009, the PUCO approved the Ohio Companies’ request for the new fuel rider, subject to further review, allowed current recovery of those costs for OE and TE, and ~~approximately May 2009~~allowed CEI to collect a portion of those costs currently and defer the remainder. The PUCO also ordered the Ohio Companies to file additional information in order for ~~CEI.~~

it to determine that the costs incurred are prudent and whether the recovery of such costs is necessary to avoid a confiscatory result. The Ohio Companies filed an application for rehearing on that order on January 26, 2009. The applications for rehearing remain pending and the Ohio Companies are unable to predict the ultimate resolution of these issues.

On ~~July 10, 2007,~~January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies and further ordered that a conference be held on February 5, 2009 to discuss the Staff’s proposal. The Ohio Companies, PUCO Staff, and other parties participated in that conference, and in a subsequent conference held on February 17, 2009. Following discussions with the Staff and other parties regarding the Staff’s proposal, on February 19, 2009, the Ohio Companies filed an amended ESP application, ~~with the PUCO requesting approval of a comprehensive supply plan for providing retail generation service to customers who do not purchase electricity from~~including an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour would reflect an average of the prices resulting from all bids. In their filing,attached Stipulation and Recommendation that was signed by the Ohio Companies, ~~offered two alternatives for structuring~~ the bids, either by customer class or a slice-of-system approach. A slice-of-system approach would require the successful bidder to be responsible for supplying a fixed percentage of the utilitys total load notwithstanding the customers classification. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Initial and reply comments on the proposal were filed by various parties in September and October, 2007, respectively. The proposal is currently pending before the PUCO.

On September 25, 2007, the Ohio Governors proposed energy plan was officially introduced into the Ohio Senate. The bill proposes to revise state energy policy to address electric generation pricing after 2008, establish advanced energy portfolio standards and energy efficiency standards, and create GHG emissions reporting and carbon control planning requirements. The bill also proposes to move to a hybrid system for determining rates for default service in which electric utilities would provide regulated generation service unless they satisfy a statutory burden to demonstrate the existence of a competitive market for retail electricity. The Senate Energy & Public Utilities Committee conducted hearings on the bill and received testimony from interested parties, including the Governors Energy Advisor, the ChairmanStaff of the PUCO, ~~consumer groups, utility executives~~ and ~~others. Several proposed amendments to the bill were submitted, including those from Ohios investor-owned electric utilities. A substitute version~~many of the ~~bill,~~intervening parties representing a diverse range of interests, which ~~incorporated certain~~substantially reflected the terms as proposed by the Staff as modified through the negotiations of the ~~proposed amendments, was introduced into~~parties. Specifically, the ~~Senate Energy & Public Utilities Committee on October 25, 2007 and was passed~~stipulated ESP provides that generation will be provided by FES at the Ohio Senate on October 31, 2007. The bill as passed by the Senate is now being considered by the House Public Utilities Committee, which has conducted hearings on the bill. Testimony has been received from interested parties, including the Chairmanaverage wholesale rate of the ~~PUCO, consumer groups, utility executives~~RFP process described above for April and ~~others. At this time,~~May 2009 to the Ohio Companies ~~cannot predict~~for their non-shopping customers and that for the period of June 1, 2009 through May 31, 2011, retail generation prices will be based upon the outcome of a descending clock CBP on a slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of any increase resulting from this CBP process ~~nor determine~~by authorizing deferral of related purchased power costs, subject to specified limits. The proposed ESP further provides that the ~~impact, if any, such legislation may have~~Ohio Companies will not seek a base distribution rate increase with an effective date before January 1, 2012, that CEI will agree to write-off approximately $215 million of its Extended RTC balance, and that the Ohio Companies will collect a delivery service improvement rider at an overall average rate of $.002 per kWh for the period of April 1, 2009 through December 31, 2011. If the Stipulated ESP is approved, one-time charges associated with implementing the ESP would be approximately $250 million (including the CEI Extended RTC balance), or $0.53 per share of common stock. The proposed ESP also addresses a number of other issues, including but not limited to, rate design for various customer classes, resolution of the prudence review described above and the collection of deferred costs that were approved in prior proceedings. On February 19, 2009, the PUCO attorney examiner issued an order setting this matter for hearing to begin on ~~their operations.~~February 25, 2009.

~~(C) PENNSYLVANIA~~

PPUC Rate Matters

Met-Ed and Penelec ~~have been purchasing~~purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement and various amendments. Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007.agreement. The ~~restated~~ agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days notice prior to the end of the year. The restated agreement also 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 ~~restated~~ 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~~If FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of ~~Met-Ed's~~Met-Ed’s and ~~Penelec's~~Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.

See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec ~~made a comprehensive transition rate filing with~~could be material.

On May 22, 2008, 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~~annual updates to the TSC rider for the ~~deferral~~period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of ~~transmission-related~~Met-Ed’s TSC, while at the same time allowing Met-Ed 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. Hearings and briefing for both companies are expected to conclude by the end of February 2009. The TSCs include a component from under-recovery of actual transmission costs incurred during ~~2006. In this rate filing, Met-Ed~~the prior period (Met-Ed - $144 million 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- $4 million) and ~~4.5%~~future transmission cost projections for Penelec ($50 million). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007, on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part the MEIUGs and PICAs Petition for Reconsideration; and (3) an order approving the compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.

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 expected to take place on April 7, 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on their results of operations.

As of December 31, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $512 million and $55 million, respectively. During the PPUC's annual audit of Met-Ed's and Penelec's NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in February 2007 and briefing was completed on March 28, 2007. The ALJs initial decision denied Met-Ed's and Penelec's request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. On November 8, 2007, the PPUC issued an order denying any changes in the accounting methodology for NUGs.

~~On May 2, 2007, Penn filed a plan with the PPUC for the procurement of default service supply from~~ June 2008 through May ~~2011. The filing proposed multiple, competitive RFPs with staggered delivery periods~~2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for ~~fixed-price, tranche-based, pay as bid default service supply to~~a transition approach that would recover past under-recovered costs plus carrying charges through the ~~residential~~new TSC over thirty-one months and commercial classes. The proposal would phase out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class default service would be provided through an hourly-priced service provided by Penn. Quarterly reconciliationdefer a portion of the ~~differences between the~~projected costs ~~of supply and revenues from customers was also proposed. On September 28, 2007, Penn filed a Joint Petition~~($92 million) plus carrying charges for Settlement resolving all but one issue in the case. Briefs were also filed on September 28, 2007 on the unresolved issue of incremental uncollectible accounts expense. The settlement was either supported, or not opposed,recovery through future TSCs by ~~all parties. On~~ December 20, 2007, the PPUC approved the settlement except for the full requirements tranche approach for residential customers, which was remanded to the ALJ for hearings. Under the terms of the Settlement Agreement, the default service procurement for small commercial customers will be done with multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the first RFP for small commercial load were received on February 20, 2008. In February 2008, parties filed direct and rebuttal testimony in the remand proceeding for the residential procurement approach. An evidentiary hearing was held on for February 26, 2008, and this matter will be presented to the PPUC for its consideration by March 13, 2008.

31, 2010.

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the ~~lowest~~“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 ~~companys~~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. ~~On December 12, 2007,~~As part of the ~~Pennsylvania Senate passed~~2008 state budget negotiations, the Alternative Energy Investment Act ~~which, as amended, provides over~~was enacted in July 2008 creating a $650 million ~~over ten years~~alternative energy fund to ~~implement~~increase the ~~Governor's proposal. The bill was then referred to the House Environmental Resources~~development and ~~Energy Committee where it awaits consideration.~~ use of alternative and renewable energy, improve energy efficiency and reduce energy consumption.

On ~~February 12,~~October 15, 2008, the Governor of Pennsylvania ~~House passed~~signed House Bill 2200 into law which ~~provides for~~became effective on November 14, 2008 as Act 129 of 2008. The bill addresses issues such as: energy efficiency and ~~demand management programs and targets as well as the installation of~~peak load reduction; generation procurement; time-of-use rates; smart meters ~~within ten years. Other~~and alternative energy. Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its guidelines for the filing of utilities’ energy efficiency and peak load reduction plans.

Major provisions of the legislation ~~has been introduced to address generation~~include:

power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a mix of long-term and short-term contracts and spot market purchases;

the competitive procurement process must be approved by the PPUC and may include auctions, RFPs, and/or bilateral agreements;

utilities must provide for the installation of smart meter technology within 15 years;

a minimum reduction in peak demand of 4.5% by May 31, 2013;

minimum reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and

an expanded definition of alternative energy to include additional types of hydroelectric and biomass facilities.

Legislation addressing rate mitigation and the expiration of rate caps ~~conservation~~was not enacted in 2008 but may be considered in the legislative session which began in January 2009. While the form and ~~renewable energy. The final form~~impact of ~~this pending~~such legislation is ~~uncertain. Consequently,~~uncertain, several legislators and the ~~Pennsylvania Companies are unable~~Governor have indicated their intent to ~~predict what impact, if any, such legislation may have~~address these issues in 2009.

On September 25, 2008, Met-Ed and Penelec filed a Voluntary Prepayment Plan with the PPUC that would provide an opportunity for residential and small commercial customers to prepay an amount on their ~~operations.~~monthly electric bills during 2009 and 2010 that would earn interest at 7.5% and be used to reduce electric rates in 2011 and 2012. Met-Ed, Penelec, OCA and OSBA have reached a settlement agreement on the Voluntary Prepayment Plan and have jointly requested that the PPUC approve the settlement. The ALJ issued a decision on January 29, 2009, recommending approval and adoption of the settlement without modification.

On February 20, 2009, Met-Ed and Penelec filed a generation procurement plan covering the period January 1, 2011 through May 31, 2013, with the PPUC. The companies’ plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. Met-Ed and Penelec have requested PPUC approval of their plan by October 2009.

NJBPU Rate Matters

~~(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, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of December 31, ~~2007,~~2008, the accumulated deferred cost balance totaled approximately ~~$322~~$220 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set.

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. ~~An April 23, 2008~~A public hearing on these proposed rules ~~is expected to be scheduled with~~was held on April 23, 2008 and comments from interested parties ~~expected to be due on~~were submitted by May ~~17,~~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~~Governor’s Office and the ~~Governor's~~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

The EMP was issued on October ~~2006, the current EMP process was initiated with the issuance of a proposed set of objectives which, as to electricity, included the following:~~22, 2008, establishing five major goals:

▪

~~Reduce the total projected electricity demand by~~maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020;

▪

~~Meet 22.5% of New Jerseys~~reduce peak demand for electricity ~~needs with renewable energy resources~~ by ~~that date;~~

▪

~~Reduce air pollution related to energy use;~~

▪

~~Encourage and maintain economic growth and development;~~

▪

~~Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index~~5,700 MW by 2020;

▪

~~Maintain unit prices for electricity to no more than +5%~~meet 30% of the ~~regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia); and~~

▪

~~Eliminate transmission congestion~~state’s electricity needs with renewable energy by ~~2020.~~2020;

~~Comments on the objectives~~

examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and

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

The EMP will be followed by appropriate legislation and participation in the development of the EMP have been solicited and a number of working groups have been formed to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing: (1) energy efficiency and demand response; (2) renewables; (3) reliability; and (4) pricing issues, have completed their assigned tasks of data gathering and analysis and have provided reports to the EMP Committee. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected in 2008.regulation as necessary. At this time, ~~JCP&L~~FirstEnergy cannot ~~predict the outcome of this process nor~~ determine the impact, if any, ~~such legislation~~the EMP may have on its ~~operations.~~operations or those of JCP&L.

On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published inIn support of the New Jersey ~~Register, which proposal~~Governor’s Economic Assistance and Recovery Plan, JCP&L announced its intent to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. An estimated $40 million will be ~~subsequently considered by~~spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. Approximately $34 million will be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million will be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million will be spent on energy efficiency programs that will complement those currently being offered. Completion of the ~~NJBPU following comments that were submitted in September and October 2007. At this time, JCP&L cannot predict~~projects is dependent upon regulatory approval for full recovery of the ~~outcome of this process nor determine the impact, if any, such regulations may have on its operations.~~costs associated with plan implementation.

~~(E)~~ FERC ~~MATTERS~~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. ~~FERC's~~The FERC’s intent was to eliminate ~~so-called pancaking of~~multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered ~~the~~ MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or ~~SECA)~~“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~~is pending before the FERC, and in the ~~first quarter~~meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of ~~2008.~~lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.

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. The ALJ issued an initial decision directing that the cost of all PJM transmission facilities, regardless of voltage, should be recovered through a postage stamp rate. The ALJ recommended an April 1, 2006 effective date for this change in rate design. Numerous parties, including FirstEnergy, submitted briefs opposing the ALJ's decision and recommendations. On April 19, 2007, the FERC issued an order ~~rejecting the ALJ's findings and recommendations in nearly every respect. The FERC found~~finding that the PJM transmission ~~owners~~owners’ existing ~~license plate~~“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~~“beneficiary pays” basis. The FERC found that ~~PJM's~~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~~PJM’s tariff.

598

On May 18, 2007, certain parties filed for rehearing of the ~~FERC's~~FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. 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 ~~FERC's~~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.

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~~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 ~~revenue recovery~~to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the ~~beneficiary pays~~“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~~FERC’s Trial Staff, and was certified by the Presiding ~~Judge. The FERC's action on~~Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement ~~agreement is pending.~~subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. The remaining merchant transmission cost allocation issues ~~will proceed to~~were the subject of a hearing at the FERC in May 2008. ~~On February 13, 2008, AEP appealed~~An initial decision was issued by the ~~FERC's orders~~Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the ~~federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission has also appealed these orders.~~initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.

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 ~~the~~ 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 ~~FERC's~~the FERC’s approval, the rates charged to ~~FirstEnergy's~~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.

Certain stand-alone transmission companies in MISO made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV and higher transmission facilities be spread throughout the entire MISO footprint. Further, Indianapolis Power and Light Company separately moved the FERC to reopen the record to address the cost allocation under the RECB methodology. FERC rejected these requests in an order issued January 31, 2008 again maintaining the status quo with respect to allocation of the cost of new transmission facilities in the MISO.

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~~“Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit.

~~Distribution of MISO Network Service Revenues~~Interconnection Agreement with AMP-Ohio

~~Effective February 1,~~On May 29, 2008, TE filed with the ~~MISO Transmission Owners~~FERC a proposed Notice of Cancellation effective midnight December 31, 2008, of the Interconnection Agreement ~~provides~~with AMP-Ohio. AMP-Ohio protested this filing. TE also filed a Petition for Declaratory Order seeking a ~~change~~FERC ruling, in the ~~method~~alternative if cancellation is not accepted, of ~~distributing transmission revenues among~~TE's right to file for an increase in rates effective January 1, 2009, for power provided to AMP-Ohio under the ~~transmission owners. MISO and~~Interconnection Agreement. AMP-Ohio filed 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~~pleading agreeing that TE may seek an increase in rates, but arguing that any increase is limited to the ~~transmission owners, that all network transmission service revenues, whether collected~~cost of generation owned by ~~MISO or directly by~~TE affiliates. On August 18, 2008, 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 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 ATSIs 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 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 Electrics bundled load cannot be charged by MISO for network service. On January 31, 2008, FERC issued an order ~~conditionally accepting~~that suspended the ~~tariff amendment subject~~cancellation of the Agreement for five months, to ~~a minor compliance filing. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement.~~

~~MISO Ancillary Services Market and Balancing Area Consolidation~~

~~MISO made a filing~~become effective on September 14, 2007 to establish Ancillary Services markets 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. An effective date of June 1, ~~2008 was requested~~2009, and established expedited hearing procedures on issues raised in the ~~filing.~~

~~MISO's previous~~ filing ~~to establish an Ancillary Services market was rejected without prejudice by FERC on June 22, 2007, subject to MISO providing an analysis~~and TE’s Petition for Declaratory Order. On October 14, 2008, the parties filed a settlement agreement and mutual notice of market power within its footprint and a plan to ensure reliability during the consolidation of balancing areas. MISO made a September 14 filing addressing the FERC's directives. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas, but filed objections on specific aspectscancellation of the ~~MISO proposal. Interventions~~Interconnection Agreement effective midnight December 31, 2008. On October 24, 2008 the presiding judge certified the settlement agreement as uncontested and ~~protests to MISO's filing were made with FERC on October 15, 2007. FERC conducted a technical conference on certain aspects of the MISO proposal~~ on December ~~6, 2007,~~22, 2008, the FERC issued an order approving the uncontested settlement agreement. This latest action terminates the litigation and ~~additional comments were filed by FirstEnergy and other parties on December 19, 2007. FERC action is anticipated in~~ the ~~first quarter of 2008.~~Interconnection Agreement.

~~Duquesnes~~

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. Duquesne’s proposed move would affect numerous FirstEnergy interests, including but not limited to the MISO. In its filing, Duquesne asked 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, 2010. 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 Duquesnes filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesnes proposal. Consequently, on December 4, 2007 and January 3, 2008, FirstEnergy submitted responsive filings that, while conceding Duquesnes rights to exit PJM, contested various aspects of Duquesnes proposal. FirstEnergy particularly focused on Duquesnes proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesnes failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use theterms under which FirstEnergy’s Beaver Valley Plant would continue to ~~meet existing commitments~~participate in PJM’s energy markets. FirstEnergy, therefore, intervened and participated fully in all of the ~~PJM capacity markets~~FERC dockets that were related to Duquesne’s proposed move.

In November, 2008, Duquesne and other parties, including FirstEnergy, negotiated a settlement that would, among other things, allow for Duquesne to ~~serve native load. Additionally, FirstEnergy protested Duquesnes failure to identify or address a number of legal, financial or operational issues and uncertainties that may or will result for both~~remain in PJM and ~~MISO market participants. Other market participants also submitted filings contesting Duquesnes plans.~~

~~On January 17, 2008, the FERC conditionally approved Duquesnes request to exit PJM. Among other conditions, FERC obligated~~provide for a methodology for Duquesne to ~~pay~~meet the PJM capacity obligations for the 2011-2012 auction that ~~had accrued prior~~excluded the Duquesne load. The settlement agreement was filed on December 10, 2008 and approved by the FERC in an order issued on January 29, 2009. The MISO opposed the settlement agreement pending resolution of exit fees alleged to ~~January 17, 2008. Duquesne was given until February 1,~~be owed by Duquesne. The FERC did not resolve this issue in its order.

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 ~~provide~~collectively as the RPM Buyers) filed a complaint at the FERC ~~written notice of its intent to withdraw and Duquesne filed the notice on February 1~~st~~. The FERC's order took notice~~against PJM alleging that three of the ~~numerous transmission~~four transitional RPM auctions yielded prices that are unjust and ~~other issues raised~~unreasonable under the Federal Power Act. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’ request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties tosubmitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the ~~proceeding, but did not provide any responsive rulings or other guidance. Rather, FERC ordered Duquesne to make~~Chief Judge issued an order terminating settlement talks. On February 9, 2009, PJM and a ~~compliance filing in forty-five days from~~group of stakeholders submitted an offer of settlement.

On October 20, 2008, the ~~FERC order (or by March 3, 2008) detailing how Duquesne will satisfy its obligations under~~RPM Buyers filed a request for rehearing of the ~~PJM Transmission Owner's Agreement.~~FERC’s September 19, 2008 order. The FERC ~~likewise directed~~has not yet ruled on the MISO to submit a compliance filing in forty-five days (or by March 3, 2008) detailing the MISO's plans to integrate Duquesne into the MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesnes transition into the MISO. On February 19, 2008, FirstEnergy asked for clarification or rehearing ~~of certain of the matters addressed in FERC's January 17, 2008 Order.~~request.

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~~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~~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~~load-serving entities in its state. FirstEnergy ~~generally supports~~believes the proposal ~~as it~~ promotes a mechanism that will result in ~~long-term~~ 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. ~~FirstEnergy does not expect this filing to impose additional supply costs since its load serving entities in MISO are already bound by similar planning reserve requirements established by~~ ~~ReliabilityFirst~~ ~~Corporation.~~ Comments on the filing were filed on January 28, 2008. ~~An effective date of~~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 ~~1, 2009 was requested in~~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 ~~filing, but MISO has requested FERC approval by~~enforcement mechanism for the ~~end of~~reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the ~~first quarter of 2008.~~

~~Organized Wholesale Power Markets~~resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.

On ~~February 21,~~October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a ~~NOPR through which it proposes~~compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to ~~adopt new rules that it states will “improve operations in organized electric markets, boost competition~~be capacity resources, load forecasting, loss of load expectation, and ~~bring additional benefits to consumers.” The proposed rule addresses demand response~~planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FirstEnergy has not yet had an opportunity to evaluateprice responsive demand. Finally, the ~~impact of the proposed rule on its operations.~~

~~10. CAPITALIZATION~~

~~(A) RETAINED EARNINGS (ACCUMULATED DEFICIT)~~

There are no restrictions on retained earnings for payment of cash dividends on OE's, CEI's, TE's, JCP&L's and FES' common stock. In general, Met-Ed's and Penelec's respective first mortgage indentures restrict the payment of dividends or distributions on or with respect to each of the company's common stock to amounts credited to earned surplus since the dateFERC largely denied rehearing of its ~~indenture. As~~March 26 order with the exception of ~~December 31, 2007, Penelec had retained earnings available~~issues related to ~~pay common stock dividends~~behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of ~~$48 million, net of amounts restricted under its first mortgage indenture. Met-Ed had an accumulated deficit of $139 million as of December 31, 2007, and~~orders on these compliance filings is ~~therefore restricted from making cash dividend distributions~~not expected to ~~FirstEnergy.~~

~~(B) PREFERRED AND PREFERENCE STOCK~~

~~No preferred shares or preference shares are currently outstanding. The following table details~~delay the ~~change in preferred shares outstanding~~June 1, 2009, start date for ~~OE, CEI, TE and JCP&L for the three years ended December 31, 2007.~~MISO Resource Adequacy.

Not Subject to Subject to
Mandatory Redemption Mandatory Redemption
Par or Par or
Number Stated Number Stated
of Shares Value of Shares Value
(Dollars in thousands)
OE
Balance, January 1, 2005 1,000,699 $ 100,070 127,500 $ 12,750
Redemptions-
7.750% Series (250,000 ) (25,000 )
7.625% Series (127,500 ) (12,750 )
Balance, December 31, 2005 750,699 75,070 - -
Redemptions-
3.90% Series (152,510 ) (15,251 )
4.40% Series (176,280 ) (17,628 )
4.44% Series (136,560 ) (13,656 )
4.56% Series (144,300 ) (14,430 )
4.24% Series (40,000 ) (4,000 )
4.25% Series (41,049 ) (4,105 )
4.64% Series (60,000 ) (6,000 )
Balance, December 31, 2006 - - - -
Balance, December 31, 2007 - $ - - $ -
CEI
Balance, January 1, 2005 974,000 $ 96,404 40,000 $ 4,009
Redemptions-
$7.40 Series A (500,000 ) (50,000 )
Adjustable Series L (474,000 ) (46,404 )
$7.35 Series C (40,000 ) (4,000 )
Amortization of fair market
value adjustments-
$7.35 Series C (9 )
Balance, December 31, 2005 - - - -
Balance, December 31, 2006 - - - -
Balance, December 31, 2007 - $ - - $ -
TE
Balance, January 1, 2005 4,110,000 $ 126,000
Redemptions-
Adjustable Series A (1,200,000 ) (30,000 )
Balance, December 31, 2005 2,910,000 96,000
Redemptions-
$4.25 Series (160,000 ) (16,000 )
$4.56 Series (50,000 ) (5,000 )
$4.25 Series (100,000 ) (10,000 )
$2.365 Series (1,400,000 ) (35,000 )
Adjustable Series B (1,200,000 ) (30,000 )
Balance, December 31, 2006 - -
Balance, December 31, 2007 - $ -
JCP&L
Balance, January 1, 2005 125,000 $ 12,649
Balance, December 31, 2005 125,000 12,649
Redemptions-
4.00% Series (125,000 ) (12,649 )
Balance, December 31, 2006 - -
Balance, December 31, 2007 - $ -

6310

FES Sales to Affiliates

~~The Companies preferred stock~~On October 24, 2008, FES, on its own behalf and ~~preference stock authorizations are as follows:~~

Preferred Stock Preference Stock
Shares Par Shares Par
Authorized Value Authorized Value
OE 6,000,000 $ 100 8,000,000 no par
OE 8,000,000 $ 25
Penn 1,200,000 $ 100
CEI 4,000,000 no par 3,000,000 no par
TE 3,000,000 $ 100 5,000,000 $ 25
TE 12,000,000 $ 25
JCP&L 15,600,000 no par
Met-Ed 10,000,000 no par
Penelec 11,435,000 no par

~~(C) LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS~~

~~Securitized Transition Bonds~~

~~JCP&L's consolidated financial statements include the results~~on behalf 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 associatedits generation-controlling subsidiaries, filed an application 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~~FERC seeking a waiver of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of December 31, 2007, $397 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 annual servicing fees of up to $628,000 that are payable from TBC collections.

~~Other Long-term Debt~~

Each of the Companies, except for JCP&L, has a first mortgage indenture under which it issues FMB secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. JCP&L satisfied the provision of its senior note indenture for the release of all FMBs held as collateral for senior notes in May 2007, subsequently repaid its other remaining FMBs and, effective September 14, 2007, discharged and released its mortgage indenture.

affiliate sales restrictions between FES and the ~~Companies have various debt covenants under their respective financing arrangements.~~Ohio Companies. The ~~most restrictive~~purpose of the ~~debt covenants relate~~waiver is to ensure that FES will be able to continue supplying a material portion of the ~~nonpayment~~electric load requirements of ~~interest and/~~the Ohio Companies in January 2009 pursuant to either an ESP or ~~principal on debt~~MRO as filed with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. On December 23, 2008, the FERC issued an order granting the waiver request and the ~~maintenance of certain financial ratios. There also exist cross-default provisions among financing arrangements of FirstEnergy, FES and~~Ohio Companies made the ~~Companies.~~required compliance filing on December 30, 2008.

~~Based on~~On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and Waverly effective November 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of ~~FMB authenticated~~capacity and energy required to be supplied by FES in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the ~~respective mortgage bond trustees through December 31, 2007,~~default or failure of supply of their committed resources. Prices for the Companies' annual sinking fund requirement for all FMB issued under the various mortgage indentures amounted to $50 million (Penn - $5 million, JCP&L - $16 million, Met-Ed - $8 million and Penelec - $21 million). Penn expects to deposit funds with its mortgage bond trustee in 2008 that will then be withdrawn upon the surrender for cancellation of a like principal amount of FMB, specifically authenticated for such purposes against unfunded property additions or against previously retired FMB. This method can result in minor increasespower provided by FES were not changed in the ~~amount~~Third Restated Partial Requirements Agreement.

Capital Requirements

Anticipated capital expenditures for the Utilities, FES and FirstEnergy’s other subsidiaries for the years 2009 through 2013, excluding nuclear fuel, are shown in the following table. Such costs include expenditures for the betterment of existing facilities and for the ~~annual sinking fund requirement. Met-Ed~~construction of generating capacity, facilities for environmental compliance, transmission lines, distribution lines, substations and ~~Penelec could fulfill their sinking fund obligations by providing bondable property additions, previously retired FMB or cash to the respective mortgage bond trustees.~~other assets.

	2008		Capital Expenditures Forecast
	Actual(1)		2009			2010-2013	Total
	(In millions)
OE	$	140	$	130	$	600	$	730
Penn		35		22		112		134
CEI		139		103		494		597
TE		57		48		202		250
JCP&L		177		160		812		972
Met-Ed		108		97		447		544
Penelec		129		122		484		606
ATSI		46		39		177		216
FGCO		1,037		635		1,373		2,008
NGC		115		243		1,323		1,566
Other subsidiaries		167		58		458		516
Total	$	2,150	$	1,657	$	6,482	$	8,139

(1) Excludes nuclear fuel, the purchase of lessor equity interests in Beaver Valley Unit 2 and Perry ($438 million), and the acquisition of Signal Peak ($125 million).

During the 2009-2013 period, maturities of, and sinking fund requirements for, long-term debt of FirstEnergy and its subsidiaries are:

	Long-Term Debt Redemption Schedule
	2009			2010-2013	Total
	(In millions)

FirstEnergy	$	-	$	1,500	$	1,500
FES		42		254		296
OE		-		1		1
Penn(1)		1		5		6
CEI(2)		150		300		450
JCP&L		29		133		162
Met-Ed		-		250		250
Penelec		100		59		159
Other		1		64		65
Total	$	323	$	2,566	$	2,889

(1) Penn has an additional $63 million due to associated companies in 2010-2013.
(2) CEI has an additional $85 million due to associated companies in 2010-2013.

6411

~~The sinking fund requirements~~NGC's investments for ~~FES and~~additional nuclear fuel during the ~~Companies for FMB and maturing long-term debt (excluding capital leases) for~~2009-2013 period are estimated to be approximately $1.3 billion, of which about $342 million applies to 2009. During the ~~next five years are:~~

Sinking Fund Requirements FES OE CEI JCP&L Met-Ed
Penelec

(In millions)
2008 $ 1,441 $ 333 $ 207 $ 27 $ - $ -
2009 - 2 162 29 - 100
2010 15 65 18 31 100 59
2011 - 1 20 32 - -
2012 - 1 22 34 - -

~~TE has no sinking fund requirements for the next five years.~~

~~Included in the table above~~same period, its nuclear fuel investments are ~~amounts for certain variable interest rate pollution control revenue bonds that currently bear interest in an interest rate mode that permits individual debt holders~~expected to ~~put the respective debt back to the issuer for purchase prior to maturity. These amounts are $1.7~~be reduced by approximately $1.0 billion and ~~$15~~$137 million, ~~in 2008 and 2010,~~ respectively, representing the next time the debt holders may exercise this right. The applicable pollution control revenue bond indentures provide that bonds so tendered for purchase will be remarketed by a designated remarketing agent. These amounts for FES, OE and CEI are shown as follows:

Year FES OE CEI
(In millions)
2008 $ 1,441 $ 156 $ 82
2010 15 - -

Obligations to repay certain pollution control revenue bonds are secured by several series of FMB. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank LOCs of $1.6 billion as of December 31, 2007, or noncancelable municipal bond insurance of $593 million as of December 31, 2007, to pay principal of, or interest on, the applicable pollution control revenue bonds. To the extent that drawings are made under the LOCs or the policies, FGCO, NGC and the Companies are entitled to a credit against their obligation to repay those bonds. FGCO, NGC and the Companies pay annual fees of 0.15% to 1.70% of the amounts of the LOCs to the issuing banks and 0.15% to 0.16% of the amounts of the insurance policies to the insurers and are obligated to reimburse the banks or insurers, as the case may be, for any drawings thereunder. Certain of the issuing banks and insurers hold FMB as security for such reimbursement obligations. These amounts and percentages for FES and the Companies are shown as follows:

FES OE CEI TE Met-Ed
Penelec

(In millions)
Amounts
LOCs $ 1,455 * $ 158 $ - $ - $ - $ -
Insurance Policies 456 16 6 4 42 69

Fees
LOCs 0.15% to 0.775 % 1.70 % - - - -
Insurance Policies 0.15 % - - - 0.16 % 0.16 %

* Includes LOC of $490 million issued for FirstEnergy on behalf of NGC

CEI and TE have unsecured LOCs of approximately $194 million in connection with the sale and leaseback of Beaver Valley Unit 2 for which they are jointly and severally liable. OE has LOCs of $291 million and $134 million in connection with the sale and leaseback of Beaver Valley Unit 2 and Perry Unit 1, respectively. OE entered into a Credit Agreement pursuant to which a standby LOC was issued in support of approximately $236 million of the Beaver Valley Unit 2 LOCs and the issuer of the standby LOC obtained the right to pledge or assign participations in OE's reimbursement obligations under the credit agreement to a trust. The trust then issued and sold trust certificates to institutional investors that were designed to be the credit equivalent of an investment directly in OE.

~~11. ASSET RETIREMENT OBLIGATIONS~~

~~FES and the Companies have 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, FES and the Companies have recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47, which was implemented on December 31, 2005.

The ARO liabilities for FES, OE and TE primarily relate to the nuclear decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities (OE for its leasehold interest in Beaver Valley Unit 2 and Perry and TE for its leasehold interest in Beaver Valley Unit 2). The ARO liabilities for JCP&L, Met-Ed and Penelec primarily relate to the nuclear decommissioning of the TMI-2 nuclear generating facility. FES and the Companies use an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs.

In 2006, FES and OE revised the ARO associated with Perry as a result of revisions to the 2005 decommissioning study. The present value of revisions in the estimated cash flows associated with projected decommissioning costs increased the ARO and corresponding plant asset for Perry by $4 million. The ARO for FES sludge disposal pond located near the Bruce Mansfield Plant was revised in 2006 due to an updated cost study. The present value of revisions in the estimated cash flows associated with projected remediation costs associated with the site decreased the ARO and corresponding plant asset by $6 million. In May 2006, CEI sold its interest in the Ashtabula C plant. As part of the transaction, CEI settled the $6 million ARO that had been established with the adoption of FIN 47.

FES and the Companies maintain nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. The fair value of the decommissioning trust assets as of December 31, 2007 and 2006 were as follows:

2007

2006

(In millions)
FES
$ 1,333 $ 1,238
OE
127 118
TE
67 61
JCP&L
176 164
Met-Ed
287 270
Penelec
138 125

FIN 47 provides accounting standards for conditional retirement obligations associated with tangible long-lived assets, requiring recognition of the fair value of a liability for an ARO in the period in which itfuel is incurred if a reasonable estimate can be identified. FIN 47 states that an obligation exists even though there may be uncertainty about timing or method of settlement and further clarifies SFAS 143, stating that the uncertainty surrounding the timing and method of settlement when settlement is conditional on a future event occurring should be reflected in the measurement of the liability, not in the recognition of the liability. Accounting for conditional ARO under FIN 47 is the same as described above for SFAS 143.

Applicable legal obligations as defined under the new standard were identified at FES active and retired generating units and the Companies substation control rooms, service center buildings, line shops and office buildings, identifying asbestos remediation as the primary conditional ARO. As a result of adopting FIN 47 in December 2005, after-tax charges of $8.8 million for FES, $16.3 million for OE, $3.7 million for CEI, $0.3 million for Met-Ed and $0.8 million for Penelec were recorded as the cumulative effect of a change in accounting principle.consumed.

The following table ~~describes~~displays operating lease commitments, net of capital trust cash receipts for the ~~changes to the ARO balances during 2007 and 2006.~~

ARO Reconciliation FES OE CEI TE JCP&L Met-Ed Penelec
(In millions)
Balance as of January 1, 2006 $ 716 $ 83 $ 8 $ 25 $ 80 $ 142 $ 72
Liabilities incurred - - - - - - -
Liabilities settled - - (6 ) - - - -
Accretion 46 5 - 2 4 9 5
Revisions in estimated
cashflows (2 ) - - - - - -
Balance as of December 31, 2006 760 88 2 27 84 151 77
Liabilities incurred - - - - - - -
Liabilities settled (1 ) - - - - - -
Accretion 51 6 - 1 6 10 5
Revisions in estimated
cashflows - - - - - - -
Balance as of December 31, 2007 $ 810 $ 94 $ 2 $ 28 $ 90 $ 161 $ 82

2009-2013 period.

~~12. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT~~

	Net Operating Lease Commitments
	2009				2010-2013		Total
	(In millions)

OE	$	103		$	390		$	493
CEI(1)		(38	)		(196	)		(234	)
TE		41			134			175
JCP&L		8			15			23
Met-Ed		4			7			11
Penelec		4			5			9
FESC		8			34			42
FGCO		176			787			963
NGC(2)		(103	)		(413	)		(516	)
Total	$	203		$	763		$	966

(1) Reflects CEI's investment in Shippingport that purchased lease obligations bonds issued on behalf of lessors in Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. Effective October 16, 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO.
(2) Reflects NGC’s purchase of lessor equity interests in Beaver Valley Unit 2 and Perry in the second quarter of 2008.

FirstEnergy has been notified by the lessor of certain vehicle and equipment leases of its election to terminate the lease arrangements effective November 2009. FirstEnergy is currently pursuing replacement lease arrangements with alternative lessors. In the event that replacement lease arrangements are not secured, FirstEnergy would be required to purchase the vehicles and equipment under lease at their unamortized value of approximately $100 million upon termination of the lease.

FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy and its subsidiaries' business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2009 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

FirstEnergy had approximately $2.4 billion of short-term indebtedness as of December 31, 2008, comprised of $2.3 billion in borrowings under the $2.75 billion revolving line of credit described below and $102 million of other bank borrowings. Total short-term bank lines of committed credit to FirstEnergy, FES and the ~~Companies~~Utilities as of December 31, 2008 were approximately $4.0 billion.

FirstEnergy, along with certain of its subsidiaries, are ~~parties~~party to a $2.75 billion five-year revolving credit facility. FirstEnergy ~~may~~has the ability to request an increase in the total commitments available under this facility up to a maximum of $3.25 ~~billion.~~billion, subject to the discretion of each lender to provide additional commitments. Commitments under the facility are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations. The annual facility fee is 0.125%.

~~On December 28, 2007,~~As of January 31, 2009, FirstEnergy had $720 million of bank credit facilities in addition to the ~~FERC issued~~$2.75 billion revolving credit facility. Also, an ~~order authorizing JCP&L, Penn, Met-Ed and Penelec to issue short-term debt securities up to $428~~aggregate of $550 million ~~$39 million, $300 million and $300 million, respectively, during the period commencing January 1, 2008 through December 31, 2009.~~

~~The Companies, with the exception~~ of ~~TE and JCP&L, each have a wholly owned subsidiary whose borrowings are secured by customer~~ accounts receivable ~~purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables~~ financing ~~arrangement~~facilities through the Ohio and Pennsylvania Companies may be accessed to meet working capital requirements and for other general corporate purposes. FirstEnergy's available liquidity as ~~a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any~~ of ~~its remaining assets could be available to its parent company. The receivables financing borrowing capacity by company are shown~~January 31, 2009, is described in the following table. ~~There were~~

Company	Type	Maturity	Commitment		Available Liquidity as of January 31, 2009
			(In millions)
FirstEnergy(1)	Revolving	Aug. 2012	$	2,750	$	405
FirstEnergy and FES	Revolving	May 2009		300		300
FirstEnergy	Bank lines	Various(2)		120		20
FGCO	Term loan	Oct. 2009(3)		300		300
Ohio and Pennsylvania Companies	Receivables financing	Various(4)		550		469
		Subtotal	$	4,020	$	1,494
		Cash		-		1,110
		Total	$	4,020	$	2,604

(1)

FirstEnergy Corp. and subsidiary borrowers.

(2)

$100 million matures November 30, 2009; $20 million uncommitted line of credit with no maturity date.

(3)

Drawn amounts are payable within 30 days and may not be re-borrowed.

(4)

$370 million expires February 22, 2010; $180 million expires December 18, 2009.

FirstEnergy's primary source of cash for continuing operations as a holding company is cash from the operations of its subsidiaries. During 2008, the holding company received $995 million of cash dividends on common stock from its subsidiaries and paid $671 million in cash dividends to common shareholders.

As of December 31, 2008, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.8 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMBs by OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding ~~borrowings~~secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $168 million, $179 million and $117 million, respectively, as of December 31, ~~2007.~~

Subsidiary Company

Parent
Company

Capacity

Annual
Facility Fee

(In millions)
OE's Capital, Incorporated OE $ 170 0.15 %
Centerior Funding Corp. CEI 200 0.15
Penn Power Funding LLC Penn 25 0.13
Met-Ed Funding LLC Met-Ed 80 0.13
Penelec Funding LLC Penelec 75 0.13
$ 550

~~The weighted average interest rates on short-term borrowings outstanding~~2008. On June 19, 2008, FGCO established an FMB indenture. Based upon its net earnings and available bondable property additions as of December 31, ~~2007~~2008, FGCO had the capability to issue $3.0 billion of additional FMBs under the terms of that indenture. Met-Ed and ~~2006 were~~Penelec had the capability to issue secured debt of approximately $376 million and $318 million, respectively, under provisions of their senior note indentures as ~~follows:~~of December 31, 2008.

2007

2006

FES
5.23 % 5.62 %
OE
4.80 % 4.04 %
CEI
5.10 % 5.66 %
TE
5.04 % 5.41 %
JCP&L
5.04 % 5.62 %
Met-Ed
5.17 % 5.62 %
Penelec
5.04 % 5.62 %
To the extent that coverage requirements or market conditions restrict the subsidiaries’ abilities to issue desired amounts of FMBs or preferred stock, they may seek other methods of financing. Such financings could include the sale of preferred and/or preference stock or of such other types of securities as might be authorized by applicable regulatory authorities which would not otherwise be sold and could result in annual interest charges and/or dividend requirements in excess of those that would otherwise be incurred.

~~13. COMMITMENTS, GUARANTEES AND CONTINGENCIES~~On September 22, 2008, FirstEnergy and the Shelf Registrants filed an automatically effective shelf registration statement with the SEC for an unspecified number and amount of securities to be offered thereon. The shelf registration provides FirstEnergy the flexibility to issue and sell various types of securities, including common stock, preferred stock, debt securities, warrants, share purchase contracts, and share purchase units. The Shelf Registrants may utilize the shelf registration statement to offer and sell unsecured, and in some cases, secured debt securities.

Nuclear Operating Licenses

Each of the nuclear units in the FES portfolio operates under a 40-year operating license granted by the NRC. The following table summarizes the current operating license expiration dates for FES’ nuclear facilities in service.

Station	In-Service Date	Current License Expiration
Beaver Valley Unit 1	1976	2016
Beaver Valley Unit 2	1987	2027
Perry	1986	2026
Davis-Besse	1977	2017

~~(A) NUCLEAR INSURANCE~~In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively. FENOC’s application for operating license extensions for Beaver Valley Units 1 and 2 was accepted by the NRC on November 9, 2007. Similar applications are expected to be filed for Davis-Besse in 2010 and Perry in 2013. The NRC review process takes approximately two to three years from the docketing of an application. The license extension is for 20 years beyond the current license period.

Nuclear Regulation

On May 14, 2007, the Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC has conducted the employee training required by the confirmatory order and a consultant has performed follow-up reviews to ensure the effectiveness of that training. The NRC continues to monitor FENOC’s compliance with all the commitments made in the confirmatory order.

Nuclear Insurance

The Price-Anderson Act limits the public liability ~~relative~~which can be assessed with respect to ~~a single incident at~~ a nuclear power plant to ~~$10.8 billion. The~~$12.5 billion (assuming 104 units licensed to operate) for a single nuclear incident, which amount is covered ~~by a combination of~~by: (i) private insurance amounting to $300 million; and (ii) $12.2 billion provided by an industry retrospective rating ~~plan. The~~plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $118 million (but not more than $18 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s maximum potential assessment under ~~the industry retrospective rating plan~~these provisions would be ~~$402~~$470 million (OE-$40 million, NGC-$408 million, and TE-$22 million) per incident but not more than ~~$60~~$70 million (OE-$6 million, NGC-$61 million, and TE-$3 million) in any one year for each incident.

~~FES~~In addition to the public liability insurance provided pursuant to the Price-Anderson Act, FirstEnergy has also obtained insurance coverage in limited amounts for economic loss and ~~the Companies are also insured under policies for each nuclear plant. Under these policies, up to $2.75 billion is provided for~~ property damage ~~and decontamination costs. FES and~~arising out of nuclear incidents. FirstEnergy is a member of Nuclear Electric Insurance Limited (NEIL) which provides coverage (NEIL I) for the ~~Companies~~extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have ~~also obtained~~policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $2.0 billion ~~of insurance coverage~~(OE-$168 million, NGC-$1.7 billion, TE-$89 million) for replacement power ~~costs. Under these policies, FES~~costs incurred during an outage after an initial 20-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the ~~Companies can be assessed a~~accumulated funds available to the insurer. FirstEnergy’s present maximum ~~of approximately $80.9 million~~aggregate assessment for incidents at any covered nuclear facility occurring during a policy year ~~which are in excess of accumulated funds available~~would be approximately $18 million (OE-$1 million, NGC-$16 million, and TE-$1 million).

FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the ~~insurer~~operating company for ~~paying losses.~~each plant. Under these arrangements, up to $2.8 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. FirstEnergy pays annual premiums for this coverage and is liable for retrospective assessments of up to approximately $61 million (OE-$6 million, NGC-$52 million, TE-$2 million, Met Ed, Penelec and JCP&L-$1 million in total) during a policy year.

~~FES and the Companies intend~~

FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of ~~their~~FirstEnergy’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by ~~their~~FirstEnergy’s insurance policies, or to the extent such insurance becomes unavailable in the future, ~~FES and the Companies~~FirstEnergy would remain at risk for such costs.

The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.1 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds.

~~(B) GUARANTEES AND OTHER ASSURANCES~~

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1 (see Note 6). FES has unconditionally and irrevocably guaranteed all of FGCOs 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 trusts undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES lease guaranty.

~~(C) ENVIRONMENTAL MATTERS~~Environmental Matters

Various federal, state and local authorities regulate ~~FES~~FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on ~~FES~~FirstEnergy with regard to environmental matters could have a material adverse effect on ~~its~~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. ~~FES~~FirstEnergy estimates capital expenditures for environmental compliance of approximately ~~$1.4 billion~~$608 million for the period ~~2008-2012.~~2009-2013.

~~FES~~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 ~~FES~~FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

Clean Air Act Compliance

~~FES~~FirstEnergy is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to ~~$32,500~~$37,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. ~~FES~~FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the ~~Clean Air Act. FES~~CAA. FirstEnergy has disputed those alleged violations based on its ~~Clean Air Act~~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“an appropriate compliance ~~program~~program” and a disagreement regarding ~~the opacity limit~~emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.

~~FES~~FirstEnergy complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOX reductions at ~~FES~~FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. ~~FES~~FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $506 million for 2009-2010 (with $414 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above, but excludes the potential AQC expenditures related to Burger Units 4 and 5 described below. On September 8, 2008, the Environmental Enforcement Section of the DOJ sent a letter to OE regarding its view that the company was not in compliance with the Sammis NSR Litigation consent decree because the installation of an SNCR at Eastlake Unit 5 was not completed by December 31, 2006. However, the DOJ acknowledged that stipulated penalties could not apply under the terms of the Sammis NSR Litigation consent decree because Eastlake Unit 5 was idled on December 31, 2006 pending installation of the SNCR and advised that it had exercised its discretion not to seek any other penalties for this alleged non-compliance. OE disputed the DOJ's interpretation of the consent decree in a letter dated September 22, 2008. Although the Eastlake Unit 5 issue is no longer active, OE filed a dispute resolution petition on October 23, 2008, with the United States District Court for the Southern District of Ohio, due to potential impacts on its compliance decisions with respect to Burger Units 4 and 5. On December 23, 2008, OE withdrew its dispute resolution petition and subsequently filed a motion to extend the date (from December 31, 2008 to April 15, 2009), under the Sammis NSR Litigation consent decree, to elect for Burger Units 4 and 5 to permanently shut down those units by December 31, 2010, or to repower them or to install flue gas desulfurization (FGD) by later dates. On January 30, 2009, the Court issued an order extending the election date from December 31, 2008 to March 31, 2009.

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. On December 10, 2008, the EPA announced it would not finalize this proposed change to the NSR regulations.

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 ~~Clean Air Act,~~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 ~~16,~~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. ~~FGCO is not required to respond to other claims until~~On April 24, 2008, the Court ~~rules on this~~denied the motion to ~~dismiss.~~

dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.

On December 18, 2007, the state of New Jersey filed a ~~Clean Air Act~~CAA citizen suit alleging ~~new source review~~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 ~~new source review~~NSR or permitting ~~required by~~under the ~~Clean Air Act's~~CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. ~~Although~~On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it ~~remains liable for civil or criminal penalties~~ and ~~fines~~a stipulation in which the parties agreed that ~~may~~GPU, Inc. should be ~~assessed relating~~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 ~~events prior~~and from Sithe Energy is disputed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, but the Court has yet to rule on Connecticut’s Motion. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station ~~in 1999,~~based on “modifications” dating back to 1986. Met-Ed is ~~indemnified by Sithe Energy against any other liability arising~~unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.

On June 11, 2008, the EPA issued a Notice and Finding of Violation to MEW alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. MEW is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from MEW is disputed. Penelec is unable to predict the outcome of this matter.

On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether ~~it arises out~~these generating sources are complying with the NSR provisions of ~~pre-1999 or post-1999 events.~~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. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. FGCO intends to fully comply with the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter.

On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.

National Ambient Air Quality Standards

In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2)~~. FES' Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO~~2 ~~and NO~~X ~~emissions. According to the EPA, SO~~2 ~~emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015,~~, ultimately capping SO2 emissions in affected states to just 2.5 million tons ~~annually.~~annually and NOX emissions ~~will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO~~X ~~cap of~~to just 1.3 million tons annually. CAIR ~~has been~~was challenged in the United States Court of Appeals for the District of ~~Columbia.~~ 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.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. The future cost of compliance with these regulations may be substantial and ~~may~~will depend, in part, on the ~~outcome of this litigation and how CAIR is ultimately implemented.~~action taken by the EPA in response to the Court’s ruling.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of ~~Columbia, which on~~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~~cap-and-trade program. The EPA ~~must now seek judicial~~petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of ~~that~~the Court’s ruling orvacating CAMR. On February 6, 2009, the United States moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the United States’ petition and denied the industry group’s petition. Accordingly, the EPA could take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if ~~approved by~~ the ~~EPA~~Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, ~~FES~~FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.

~~W. H. Sammis Plant~~

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 NOX ~~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, FGCO, OE and Penn 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.

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The Sammis NSR Litigation consent decree also requires FirstEnergy to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.

~~On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation, or Bechtel, under which Bechtel will engineer, procure and construct AQC systems for the reduction of SO~~2 ~~emissions. FGCO also entered into an agreement with Babcock & Wilcox Company, or B&W, on August 25, 2006 to supply flue gas desulfurization systems for the reduction of SO~~2 ~~emissions. SCR systems for the reduction of NO~~X ~~emissions are also being installed at the Sammis Plant under a 1999 Agreement with B&W.~~

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 change 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.~~

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, including CO2, emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it ~~failed to receive the two-thirds vote required~~was never submitted for ratification by the United States Senate. However, the Bush administration ~~has~~had 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, former 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. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity in the United States comes from renewable sources by 2012, and 25% by 2025; and implementing an economy-wide cap-and-trade program to reduce GHG emissions 80% by 2050.

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~~Environment and Public Works ~~Committees~~Committee has passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as ~~air pollutants~~“air pollutants” under the ~~Clean Air Act.~~CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the ~~Clean Air Act~~CAA to regulate ~~air pollutants~~“air pollutants” from those and other facilities. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting input from the public on the effects of climate change and the potential ramifications of regulation of CO2 under the CAA.

~~FES~~FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWH of electricity generated by ~~FES~~FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to ~~FES~~FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to ~~FES~~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 ~~EPAs~~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 ~~(BPJ)~~ to minimize impacts on fish and shellfish from cooling water intake structures. ~~FES~~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 ~~evaluating~~whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. Oral argument before the Supreme Court occurred on December 2, 2008 and a decision is anticipated during the first half of 2009. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the ~~outcome~~results of such studies, the ~~EPAs~~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 ~~BPJ,~~best professional judgment, the future ~~cost~~costs of compliance with these standards may require material capital expenditures.

The U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.

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 December 31, ~~2007, FES and the Companies~~2008, FirstEnergy had approximately ~~$1.5~~$1.7 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and ~~Perry.~~TMI-2. As part of the application to the NRC to transfer the ownership of ~~these nuclear facilities~~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~~“real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.

The ~~Companies~~Utilities have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, ~~2007,~~2008, based on estimates of the total costs of cleanup, the ~~Companies'~~Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. ~~In addition, JCP&L has~~Total liabilities of approximately $90 million have been accrued through December 31, 2008. Included in the total are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants in New ~~Jersey; those costs~~Jersey, which are being recovered by JCP&L through a non-bypassable SBC. ~~CEI, TE~~

Fuel Supply

FES currently has long-term coal contracts with various terms to provide approximately 21.5 million tons of coal for the year 2009, approximately 98% of its 2009 coal requirements of 22 million tons. This contract coal is produced primarily from mines located in Ohio, Pennsylvania, Kentucky, West Virginia and ~~JCP&L have recognized liabilities of $1.3 million, $2.5 million and $64.9 million, respectively, as of~~Wyoming. The contracts expire at various times through December 31, ~~2007.~~

~~(D) OTHER LEGAL PROCEEDINGS~~

~~Power Outages and Related Litigation~~2030. See “Environmental Matters” for factors pertaining to meeting environmental regulations affecting coal-fired generating units.

In July ~~1999,~~2008, FEV entered into a joint venture with the ~~Mid-Atlantic States experienced~~Boich Companies, a ~~severe heat wave, which resulted~~Columbus, Ohio-based coal company, to acquire a majority stake in ~~power outages throughout~~ the ~~service territories~~Bull Mountain Mine Operations, now called Signal Peak, near Roundup, Montana. This transaction is part of ~~many electric utilities, including JCP&L's territory.~~FirstEnergy’s strategy to secure high-quality fuel supplies at attractive prices to maximize the capacity of its fossil generating plants. In ~~an investigation~~a related transaction, FirstEnergy entered into a 15-year agreement to purchase up to 10 million tons of bituminous western coal annually from the ~~causes~~mine. FirstEnergy also entered into agreements with the rail carriers associated with transporting coal from the mine to its generating stations, and expects to begin taking delivery of the ~~outages~~coal in late 2009 or early 2010. The joint venture has the right to resell Signal Peak coal tonnage not used at FirstEnergy facilities and ~~the reliability~~has call rights on such coal above certain levels.

FirstEnergy has contracts for all uranium requirements through 2010 and a portion of uranium material requirements through 2014. Conversion services contracts fully cover requirements through 2011 and partially fill requirements through 2015. Enrichment services are contracted for all of the ~~transmission~~enrichment requirements for nuclear fuel through 2014. A portion of enrichment requirements is also contracted for through 2020. Fabrication services for fuel assemblies are contracted for both Beaver Valley units and ~~distribution systems~~Davis Besse through 2013 and through the current operating license period for Perry (through approximately 2026). The Davis-Besse fabrication contract also has an extension provision for services for three additional consecutive reload batches through the current operating license period (approximately 2017). In addition to the existing commitments, FirstEnergy intends to make additional arrangements for the supply of ~~all four~~uranium and for the subsequent conversion, enrichment, fabrication, and waste disposal services.

On-site spent fuel storage facilities are expected to be adequate for Perry through 2011; facilities at Beaver Valley Units 1 and 2 are expected to be adequate through 2015 and 2010, respectively. Davis-Besse has adequate storage through the remainder of ~~New Jerseys electric utilities,~~its current operating license period. After current on-site storage capacity at the ~~NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate~~plants is exhausted, additional storage capacity will have to be obtained either through plant modifications, interim off-site disposal, or ~~improper service~~permanent waste disposal facilities. FENOC is currently taking actions to ~~its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed~~extend the spent fuel storage capacity for Perry and Beaver Valley. Plant modifications to increase the storage capacity of the existing spent fuel storage pool at Beaver Valley Unit 2 will be submitted to the NRC for approval during the first half of 2009, with implementation scheduled for 2010. Dry fuel storage is also being pursued at Perry and Beaver Valley, with Perry implementation scheduled to begin 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.~~2010.

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~~In August~~The Federal Nuclear Waste Policy Act of 1982 provides for the construction of facilities for the permanent disposal of high-level nuclear wastes, including spent fuel from nuclear power plants operated by electric utilities. NGC has contracts with the DOE for the disposal of spent fuel for Beaver Valley, Davis-Besse and Perry. Yucca Mountain was approved in 2002 as a repository for underground disposal of spent nuclear fuel from nuclear power plants and high level waste from U.S. defense programs. The DOE submitted the ~~trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims~~license application 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 appealedYucca Mountain 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, basedNRC 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 judgmentJune 3, 2008. Based on the ~~remaining plaintiffs claims for negligence, breach of contract and punitive damages. In July 2006,~~DOE’s most recent published statements, 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. JCP&L is defending this class action but is unable to predict the outcome of this matter. No liability has been accrued as of December 31, 2007.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. Canada Power System Outage Task Forces final report in April 2004 on the outages concluded, among other things,earliest date that the ~~problems leading~~Yucca Mountain repository will start receiving spent fuel is 2020. FirstEnergy intends to the outages began in FirstEnergy's Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; andmake additional arrangements for storage capacity as a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energys Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 recommendations to prevent or minimize the scope of future blackouts. Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy's implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceedingcontingency for further delays with the ~~implementation~~DOE acceptance of ~~the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations~~spent fuel 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.disposal past 2020.

~~On February~~

Fuel oil and natural gas are used primarily to fuel peaking units and/or to ignite the burners prior to burning coal when a coal-fired plant is restarted. Fuel oil requirements have historically been low and are forecasted to remain so; requirements are expected to average approximately 5 million gallons per year over the next five years. Due to the volatility of fuel oil prices, FirstEnergy has adopted a strategy of either purchasing fixed-priced oil for inventory or using financial instruments to hedge against price risk. Natural gas is consumed primarily by peaking units, and the demand is forecasted to range from approximately 3.5 million cubic feet (Mcf) in 2009 to 2.7 Mcf in 2010. Because of high price volatility and the unpredictability of unit dispatch, natural gas futures are purchased based on forecasted demand to hedge against price movements.

System Demand

The 2008 net maximum hourly demand for each of the ~~PUCO entered an order dismissing four separate complaint cases before it~~Utilities was: OE–5,579 MW on June 9, 2008; Penn–1,063 MW on June 9, 2008; CEI–4,295 MW on June 9, 2008; TE–2,050 MW on June 9, 2008; JCP&L–6,299 MW on June 10, 2008; Met-Ed–3,045 MW on June 10, 2008; and Penelec–2,880 MW on June 9, 2008.

Supply Plan

Regulated Commodity Sourcing

The Utilities have a default service obligation to provide the required power supply to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales can vary depending on the level of shopping that occurs. Supply plans vary by state and by service territory. JCP&L’s default service supply is secured through a statewide competitive procurement process approved by the NJBPU. Penn’s default service supply is provided through a competitive procurement process approved by the PPUC. For the first quarter of 2009, the default service supply for the Ohio Companies was sourced 4% from the spot market and 96% through a competitive procurement process. Absent resolution of the ESP or MRO, the Ohio Companies anticipate conducting a similar CBP for the period beginning April 1, 2009. The default service supply for Met-Ed and Penelec is secured through a series of existing, long-term bilateral purchase contracts with unaffiliated suppliers, and through a FERC-approved agreement with FES. If any unaffiliated suppliers fail to deliver power to any one of the Utilities’ service areas, the Utility serving that area may need to procure the required power in the market in their role as a PLR.

Unregulated Commodity Sourcing

FES has retail and wholesale competitive load-serving obligations in Ohio, New Jersey, Maryland, Pennsylvania, Michigan and Illinois serving both affiliated and non-affiliated companies. FES provides energy products and services to customers under various PLR, shopping, competitive-bid and non-affiliated contractual obligations. In 2008, FES’ generation service to affiliated companies was approximately 95% of its total generation obligation. Depending upon the resolution of regulatory proceedings relating to how the ~~August 14, 2003~~Ohio Companies will obtain their supply and thereafter the results of any CBP or other procurement process implemented in accordance with PUCO requirements, FES’ service to affiliated companies may decrease, making more power ~~outages. The dismissal was filed by~~available to the ~~complainants~~competitive wholesale markets and potentially subjecting FES to greater volatility in the prices it receives for its power. Geographically, approximately 68% of FES’ obligation is located in the MISO market area and 32% is located in the PJM market area.

FES provides energy and energy related services, including the generation and sale of electricity and energy planning and procurement through retail and wholesale competitive supply arrangements. FES controls (either through ownership, lease, affiliated power contracts or participation in OVEC) 13,973 MW of installed generating capacity. FES supplies the power requirements of its competitive load-serving obligations through a combination of subsidiary-owned generation, non-affiliated contracts and spot market transactions.

Regional Reliability

FirstEnergy’s operating companies are located within MISO and PJM and operate under the reliability oversight of a regional entity known as ReliabilityFirst. This regional entity operates under the oversight of the NERC in accordance with a ~~resolution reached between~~Delegation Agreement approved by the ~~FirstEnergy companies and~~FERC. ReliabilityFirst began operations under the complainants in those four cases. Two of those cases which were originally filed in Ohio State courts involved individual complainants and were subsequently dismissed for lack of subject matter jurisdiction. Further appeals were unsuccessful. The other two complaint cases were filedNERC on January 1, 2006. On July 20, 2006, the NERC was certified by ~~various insurance carriers either in their own name~~the FERC as ~~subrogees or~~the ERO in the ~~name~~United States pursuant to Section 215 of ~~their insured, seeking reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO~~the Federal Power Act and ~~AEP,~~ReliabilityFirst was certified as ~~well) for claims paid to insureds for damages allegedly arising as~~a regional entity. ReliabilityFirst represents the consolidation of the ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils into a single regional reliability organization.

Competition

As a result of actions taken by state legislative bodies, major changes in the ~~loss~~electric utility business have occurred in portions of ~~power on August 14, 2003. (Also relating~~the United States, including Ohio, New Jersey and Pennsylvania where FirstEnergy’s utility subsidiaries operate. These changes have altered the way traditional integrated utilities conduct their business. FirstEnergy has aligned its business units to accommodate its retail strategy and participate in the ~~August 14, 2003 power outages,~~competitive electricity marketplace (see Strategy and Outlook in the 2008 Annual Report of FirstEnergy). FirstEnergy’s Competitive Energy Services segment participates in deregulated energy markets in Ohio, Pennsylvania, Maryland, Michigan, and Illinois through FES.

In New Jersey, JCP&L has procured electric supply to serve its BGS customers since 2002 through a ~~fifth case, involving another insurance company was voluntarily dismissed~~statewide auction process approved by the ~~claimant~~NJBPU. The auction is designed to procure supply for BGS customers at a cost reflective of market conditions.

FirstEnergy remains focused on managing the transition to competitive markets for electricity in ~~April 2007;~~Ohio and Pennsylvania. On May 1, 2008, the Governor of Ohio signed SB221 into law, which became effective July 31, 2008. The new law provides two options for pricing generation in 2009 and beyond – through a ~~sixth case, involving~~negotiated rate plan or a competitive bidding process (see PUCO Rate Matters above). In Pennsylvania, all electric distribution companies will be required to secure generation for customers in competitive markets by 2011. On October 15, 2008, the ~~claim~~Governor of Pennsylvania signed House Bill 2200 into law, which became effective on November 14, 2008, as Act 129 of 2008. The new law outlines a ~~non-customer seeking reimbursement~~competitive procurement process and sets targets for ~~losses incurred when its store~~energy efficiency and conservation (see PPUC Rate Matters above).

Research and Development

The Utilities participate in the funding of EPRI, which was ~~burglarized~~formed for the purpose of expanding electric research and development under the voluntary sponsorship of the nation’s electric utility industry - public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on ~~August 14, 2003 was dismissed by~~all aspects of electric power production and use, including fuels, generation, delivery, energy management and conservation, environmental effects and energy analysis. The majority of EPRI’s research and development projects are directed toward practical solutions and their applications to problems currently facing the ~~court.) The order dismissing~~electric utility industry.

FirstEnergy also participates in other research and development initiatives with industry research consortiums and universities, including for the ~~PUCO cases, noted above, concludes all pending litigation related to the August 14, 2003 outages~~development of carbon capture and ~~the resolution will not have a material adverse effect on the financial condition, results of operations or cash flows of either FirstEnergy or any of its subsidiaries.~~coal-based fuel cell technologies.

7221

Executive Officers

~~Nuclear Plant Matters~~

Name	Age	Positions Held During Past Five Years	Dates
A. J. Alexander	57	President and Chief Executive Officer	2004-present
		President and Chief Operating Officer	*-2004
W. D. Byrd	54	Vice President, Corporate Risk & Chief Risk Officer Director – Rates Strategy Director – Commodity Supply	2007-present 2004-2007 *-2004
L. M. Cavalier	57	Senior Vice President – Human Resources Vice President – Human Resources	2005-present *-2005

M. T. Clark	58	Executive Vice President – Strategic Planning & Operations Senior Vice President – Strategic Planning & Operations Vice President – Business Development	2008-present 2004-2008 *-2004

D. S. Elliott (B)	54	President – Pennsylvania Operations	2005-present
		Senior Vice President	*-2005

R. R. Grigg (A)(B)	60	Executive Vice President and President-FirstEnergy Utilities	2008-present
		Executive Vice President and Chief Operating Officer	2004-2008
J. J. Hagan	58	President and Chief Executive Officer – WE Generation President and Chief Nuclear Officer – FENOC Senior Vice President and Chief Operating Officer – FENOC Senior Vice President - FENOC	-2004 2007-present 2005-2007 -2005
C. E. Jones (A)(B)	53	Senior Vice President – Energy Delivery & Customer Service (E) President – FirstEnergy Solutions Senior Vice President – Energy Delivery & Customer Service	2009-present 2007-2009 *-2007
C. D. Lasky (D)	46	Vice President – Fossil Operations	2008-present
		Vice President – Fossil Operations & Air Quality Compliance	2004-2008
		Plant Director	*-2004

G. R. Leidich	58	Executive Vice President & President – FirstEnergy Generation	2008-present
		Senior Vice President – Operations President and Chief Nuclear Officer – FENOC	2007-2008 *-2007

D. C. Luff	61	Senior Vice President – Governmental Affairs	2007-present
		Vice President	*-2007

R. H. Marsh (A)(B)(D)	58	Senior Vice President and Chief Financial Officer	*-present

S. E. Morgan (C)(F)	58	President – JCP&L Vice President – Energy Delivery	2004-present *-2004

J. M. Murray (A)(G)	62	President – Ohio Operations Regional President – Toledo Edison Company Regional President – West	2005-present 2004-2005 *-2004

J. F. Pearson (A)(B)(D)	54	Vice President and Treasurer	2006-present
		Treasurer Group Controller – Strategic Planning and Operations Group Controller – FirstEnergy Solutions	2005-2006 2004-2005 *-2004

D. R. Schneider (D)	47	President – FirstEnergy Solutions (E) Senior Vice President – Energy Delivery & Customer Service Vice President – Energy Delivery Vice President – Commodity Operations Vice President – Fossil Operations	2009-present 2007-2009 2006-2007 2004-2006 *-2004

L.L. Vespoli (A)(B)(D)	49	Executive Vice President and General Counsel	2008-present
		Senior Vice President and General Counsel	*-2008

H. L. Wagner (A)(B)(D)	56	Vice President, Controller and Chief Accounting Officer	*-present

T. M. Welsh	59	Senior Vice President – Assistant to CEO Senior Vice President Vice President	2007-present 2004-2007 *-2004

~~On May 14, 2007, the Office~~

(A) Denotes executive officers of OE, CEI and TE.		(E) Position effective February 2, 2009.
(B) Denotes executive officers of Met-Ed and Penelec.		(F) Retiring, September 1, 2009.
(C) Denotes executive officer of JCP&L		(G) Retiring, June 1, 2009.
(D) Denotes executive officers of FES.		* Indicates position held at least since January 1, 2004.

Employees

As of ~~Enforcement~~January 1, 2009, FirstEnergy’s subsidiaries had a total of the NRC issued a Demand for Information (DFI) to FENOC, following FENOCs 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 Commissions regulations. FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRCs Demand for Information 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 NRCs Office of Enforcement after it completes the key commitments embodied14,698 employees located in the ~~NRCs order. FENOCs compliance with these commitments is subject to future NRC review.~~United States as follows:

~~Other Legal Matters~~

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to normal business operations pending against FES and the Companies. 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 has opposed. On August 2, 2007, the Court denied the plaintiffs motion to amend their complaint. The plaintiffs have appealed the Courts denial of the motion for certification as a class action and motion to amend their complaint.

	Total		Bargaining Unit
	Employees		Employees
FESC		3,355		250
OE		1,328		770
CEI		1,010		651
TE		445		321
Penn		223		165
JCP&L		1,470		1,113
Met-Ed		776		536
Penelec		994		664
ATSI		43		-
FES		219		-
FGCO		2,006		1,283
FENOC		2,829		1,031
Total		14,698		6,784

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~~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~~Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. The ~~court is expected~~Court has yet to ~~issue a briefing schedule at~~render its ~~April 2008 scheduling conference.~~decision. JCP&L recognized a liability for the potential $16 million award in 2005.

The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties are continuing to bargain with the assistance of a federal mediator. FirstEnergy has a strike mitigation plan ready in the event of a strike.

FirstEnergy Web Site

Each of the registrant’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy’s internet Web site at www.firstenergycorp.com. These reports are posted on the Web site as soon as reasonably practicable after they are electronically filed with the SEC. Information contained on FirstEnergy’s Web site shall not be deemed incorporated into, or to be part of, this report.

ITEM 1A. RISK FACTORS

We operate in a business environment that involves significant risks, many of which are beyond our control. The following risk factors and all other information contained in this report should be considered carefully when evaluating FirstEnergy and our subsidiaries. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Below, we have identified risks we currently consider material. However, our business, financial condition, cash flows or results of operations could be affected materially and adversely by additional risks not currently known to us or that we deem immaterial at this time. Additional information on risk factors is included in "Item 1. Business" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results.

Risks Related to Business Operations

Risks Arising from the Reliability of Our Power Plants and Transmission and Distribution Equipment

Operation of generation, transmission and distribution facilities involves risk, including the potential breakdown or failure of equipment or processes, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.

Operation of our power plants below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWH or may require us to incur significant costs as a result of operating our higher cost units or obtaining replacement power from third parties in the open market to satisfy our forward power sales obligations. Moreover, if we were unable to perform under contractual obligations, penalties or liability for damages could result. FES, FGCO and the Ohio Companies are exposed to losses under their applicable sale-leaseback arrangements for generating facilities upon the occurrence of certain contingent events that could render those facilities worthless. Although we believe these types of events are unlikely to occur, FES, FGCO and the Ohio Companies have a maximum exposure to loss under those provisions of approximately $1.3 billion for FES, $800 million for OE and an aggregate of $700 million for TE and CEI as co-lessees.

We remain obligated to provide safe and reliable service to customers within our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. Failure to provide safe and reliable service and failure to meet regulatory reliability standards due to a number of factors, including, but not limited to, equipment failure and weather, could adversely affect our operating results through reduced revenues and increased capital and operating costs and the imposition of penalties/fines or other adverse regulatory outcomes.

Changes in Commodity Prices Could Adversely Affect Our Profit Margins

We purchase and sell electricity in the competitive wholesale and retail markets. Increases in the costs of fuel for our generation facilities (particularly coal, uranium and natural gas) can affect our profit margins. Changes in the market price of electricity, which are affected by changes in other commodity costs and other factors, may impact our results of operations and financial position by increasing the amount we pay to purchase power to supply PLR and default service obligations in Ohio and Pennsylvania. In addition, the weakening global economy could lead to lower international demand for coal, oil and natural gas, which may lower fossil fuel prices and put downward pressure on electricity prices.

Electricity and fuel prices may fluctuate substantially over relatively short periods of time for a variety of reasons, including:

▪

changing weather conditions or seasonality;

▪

changes in electricity usage by our customers;

▪

illiquidity in wholesale power and other markets;

▪

transmission congestion or transportation constraints, inoperability or inefficiencies;

▪

availability of competitively priced alternative energy sources;

▪

changes in supply and demand for energy commodities;

▪

changes in power production capacity;

▪

outages at our power production facilities or those of our competitors;

▪

changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products; and

▪

natural disasters, wars, acts of sabotage, terrorist acts, embargoes and other catastrophic events.

We Are Exposed to Operational, Price and Credit Risks Associated With Selling and Marketing Products in the Power Markets That We Do Not Always Completely Hedge Against

We purchase and sell power at the wholesale level under market-based tariffs authorized by the FERC, and also enter into short-term agreements to sell available energy and capacity from our generation assets. If ~~it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or~~we are ~~otherwise made subject~~unable to ~~liability~~deliver firm capacity and energy under these agreements, we may be required to pay damages. These damages would generally be based on the ~~above matters,~~difference between the market price to acquire replacement capacity or energy and the contract price of the undelivered capacity or energy. Depending on price volatility in the wholesale energy markets, such damages could be significant. Extreme weather conditions, unplanned power plant outages, transmission disruptions, and other factors could affect our ability to meet our obligations, or cause increases in the market price of replacement capacity and energy.

We attempt to mitigate risks associated with satisfying our contractual power sales arrangements by reserving generation capacity to deliver electricity to satisfy our net firm sales contracts and, when necessary, by purchasing firm transmission service. We also routinely enter into contracts, such as fuel and power purchase and sale commitments, to hedge our exposure to fuel requirements and other energy-related commodities. We may not, however, hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position could be negatively affected.

The Use of Derivative Contracts by Us to Mitigate Risks Could Result in Financial Losses That May Negatively Impact our Financial Results

We use a variety of non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. Also, we could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.

Our Risk Management Policies Relating to Energy and Fuel Prices, and Counterparty Credit Are by Their Very Nature Risk Related, and We Could Suffer Economic Losses Despite Such Policies

We attempt to mitigate the market risk inherent in our energy, fuel and debt positions. Procedures have been implemented to enhance and monitor compliance with our risk management policies, including validation of transaction and market prices, verification of risk and transaction limits, sensitivity analysis and daily portfolio reporting of various risk measurement metrics. Nonetheless, we cannot economically hedge all of our exposures in these areas and our risk management program may not operate as planned. For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions reflected in our analyses. Also, our power plants might not produce the expected amount of power during a given day or time period due to weather conditions, technical problems or other unanticipated events, which could require us to make energy purchases at higher prices than the prices under our energy supply contracts. In addition, the amount of fuel required for our power plants during a given day or time period could be more than expected, which could require us to buy additional fuel at prices less favorable than the prices under our fuel contracts. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge.

Our risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as future market prices and demand for power and other energy-related commodities. These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminished if the judgments and assumptions underlying those calculations prove to be inaccurate.

We also face credit risks from parties with whom we contract who could default in their performance, in which cases we could be forced to sell our power into a lower-priced market or make purchases in a higher-priced market than existed at the time of executing the contract. Although we have established risk management policies and programs, including credit policies to evaluate counterparty credit risk, there can be no assurance that we will be able to fully meet our obligations, that we will not be required to pay damages for failure to perform or that we will not experience counterparty non-performance or that we will collect for voided contracts. If counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices. In that event, our financial results could be adversely affected.

Nuclear Generation Involves Risks that Include Uncertainties Relating to Health and Safety, Additional Capital Costs, the Adequacy of Insurance Coverage and Nuclear Plant Decommissioning

We are subject to the risks of nuclear generation, including but not limited to the following:

▪

the potential harmful effects on the environment and human health resulting from unplanned radiological releases associated with the operation of our nuclear facilities and the storage, handling and disposal of radioactive materials;

▪

limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;

▪

uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and

▪

uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed operation including increases in minimum funding requirements or costs of completion.

The NRC has broad authority under federal law to impose licensing security and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down a unit, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants, including ours. Also, a serious nuclear incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit.

Our nuclear facilities are insured under NEIL policies issued for each plant. Under these policies, up to $2.8 billion of insurance coverage is provided for property damage and decontamination and decommissioning costs. We have also obtained approximately $2.0 billion of insurance coverage for replacement power costs. Under these policies, we can be assessed a maximum of approximately $79 million for incidents at any covered nuclear facility occurring during a policy year that are in excess of accumulated funds available to the insurer for paying losses.

The Price-Anderson Act limits the public liability that can be assessed with respect to a nuclear power plant to $12.5 billion (assuming 104 units licensed to operate in the United States) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $300.0 million; and (ii) $12.2 billion provided by an industry retrospective rating plan. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $117.5 million (but not more than $17.5 million per year) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Our maximum potential exposure under these provisions would be $470.0 million per incident but not more than $70.0 million in any one year.

Capital Market Performance and Other Changes May Decrease the Value of Decommissioning Trust Fund, Pension Fund Assets and Other Trust Funds Which Then Could Require Significant Additional Funding

Our financial statements reflect the values of the assets held in trust to satisfy our obligations to decommission our nuclear generation facilities and under pension and other post-retirement benefit plans. The value of certain of the assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the trusts. If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially increase. The recent disruption in the capital markets and its effects on particular businesses and the economy in general also affects the values of the assets that are held in trust to satisfy future obligations to decommission our nuclear plants, to pay pensions to our retired employees and to pay other funded obligations. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to decommission nuclear generating stations, to pay future pensions and other obligations requires significant judgment, and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or greater liability levels can negatively impact our results of operations and financial position.

We Could be Subject to Higher Costs and/or Penalties Related to Mandatory NERC/FERC Reliability Standards

As a result of the EPACT, owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by NERC and approved by FERC. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. Compliance with new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties.

Reliability standards that were historically subject to voluntary compliance are now mandatory and could subject us to potential civil penalties for violations which could negatively impact our business. The FERC can now impose penalties of $1.0 million per day for failure to comply with these mandatory electric reliability standards.

In addition to direct regulation by the FERC, we are also subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by the FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, the independent market monitors of ISOs and RTOs may impose bidding and scheduling rules to curb the potential exercise of market power and to ensure the market functions. Such actions may materially affect our ability to sell, and the price we receive for, our energy and capacity.

We Rely on Transmission and Distribution Assets That We Do Not Own or Control to Deliver Our Wholesale Electricity. If Transmission is Disrupted Including Our Own Transmission, or Not Operated Efficiently, or if Capacity is Inadequate, Our Ability to Sell and Deliver Power May Be Hindered

We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity we sell. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by independent system operators, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products on the most favorable terms. In addition, in certain of the markets in which we operate, we may be deemed responsible for congestion costs if we schedule delivery of power between congestion zones during periods of high demand. If we are unable to recover for such congestion costs in retail rates, our financial results could be adversely affected.

Demand for electricity within our utilities’ service areas could stress available transmission capacity requiring alternative routing or curtailing electricity usage that may increase operating costs or reduce revenues with adverse impacts to results of operations. In addition, as with all utilities, potential concerns over transmission capacity could result in MISO, PJM or the FERC requiring us to upgrade or expand our transmission system, requiring additional capital expenditures.

The FERC requires wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, it is possible that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electricity as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether independent system operators in applicable markets will operate the transmission networks, and provide related services, efficiently.

Disruptions in Our Fuel Supplies Could Occur, Which Could Adversely Affect Our Ability to Operate Our Generation Facilities and Impact Financial Results

We purchase fuel from a number of suppliers. The lack of availability of fuel at expected prices, or a disruption in the delivery of fuel which exceeds the duration of our on-site fuel inventories, including disruptions as a result of weather, increased transportation costs or other difficulties, labor relations or environmental or other regulations affecting our fuel suppliers, could cause an adverse impact on our ability to operate our facilities, possibly resulting in lower sales and/or higher costs and thereby adversely affect our results of operations. Operation of our coal-fired generation facilities is highly dependent on our ability to procure coal. Although we have long-term contracts in place for our coal and coal transportation needs, power generators in the Midwest and the Northeast have experienced significant pressures on available coal supplies that are either transportation or supply related. If prices for physical delivery are unfavorable, our financial condition, results of operations and cash flows could be materially adversely affected.

Temperature Variations as well as Weather Conditions or other Natural Disasters Could Have a Negative Impact on Our Results of Operations and Demand Significantly Below or Above our Forecasts Could Adversely Affect our Energy Margins

Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, ice or snow storms, or droughts or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period.

Customer demand that we satisfy pursuant to our default service tariffs could change as a result of severe weather conditions or other circumstances over which we have no control. We satisfy our electricity supply obligations through a portfolio approach of providing electricity from our generation assets, contractual relationships and market purchases. A significant increase in demand could adversely affect our energy margins if we are required under the terms of the default service tariffs to provide the energy supply to fulfill this increased demand at capped rates, which we expect would remain below the wholesale prices at which we would have to purchase the additional supply if needed or, if we had available capacity, the prices at which we could otherwise sell the additional supply. Accordingly, any significant change in demand could have a material adverse effect on ~~FES~~our results of operations and financial position.

We Are Subject to Financial Performance Risks Related to General Economic Cycles and also Related to Heavy Manufacturing Industries such as Automotive and Steel

Our business follows the economic cycles of our customers. Declines in demand for electricity as a result of economic downturns would be expected to reduce overall electricity sales and reduce our revenues. Economic conditions also impact the rate of delinquent customer accounts receivable, further increasing our costs. A decrease in electric generation sales volume has been, and is expected to continue to be, influenced by circumstances in automotive, steel and other heavy industries.

Increases in Customer Electric Rates and the ~~Companies~~Impact of the Economic Downturn May Lead to a Greater Amount of Uncollectible Customer Accounts

Our utility operations are impacted by the economic conditions in our service territories and those conditions could negatively impact our collections of accounts receivable which could adversely impact our financial condition, results of operations and cash flows.

~~14. FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS~~The Goodwill of One or More of Our Operating Subsidiaries May Become Impaired, Which Would Result in Write-Offs of the Impaired Amounts

~~In 2005,~~Goodwill could become impaired at one or more of our operating subsidiaries. The actual timing and amounts of any goodwill impairments in future years would depend on many uncertainties, including changing interest rates, utility sector market performance, our capital structure, market prices for power, results of future rate proceedings, operating and capital expenditure requirements, the ~~Ohio Companies~~value of comparable utility acquisitions and ~~Penn transferred their respective undivided ownership interests~~other factors.

We Face Certain Human Resource Risks Associated with the Availability of Trained and Qualified Labor to Meet Our Future Staffing Requirements

We are challenged to find ways to retain our aging skilled workforce while recruiting new talent to mitigate losses in ~~FirstEnergy's nuclear~~critical knowledge and ~~non-nuclear generation assets~~skills due to ~~NGC~~retirements. Mitigating these risks could require additional financial commitments.

Significant Increases in Our Operation and ~~FGCO, respectively. All~~Maintenance Expenses, Including Our Health Care and Pension Costs, Could Adversely Affect Our Future Earnings and Liquidity

We continually focus on limiting, and reducing where possible, our operation and maintenance expenses. However, we expect to continue to face increased cost pressures, including health care and pension costs. We have experienced significant health care cost inflation in the last few years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to take requiring employees and retirees to bear a higher portion of the ~~non-nuclear assets were transferred~~costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of assumptions, many of which relate to ~~FGCO under~~factors beyond our control. These assumptions include investment returns, interest rates, health care cost trends, benefit design changes, salary increases, the ~~purchase option terms~~demographics of ~~a Master Facility Lease between FGCO~~plan participants and the Ohio Companies and Penn, under which FGCO leased, operated and maintained the assets that it now owns. CEI and TE sold their interests in nuclear generation assets at net book value to NGC, while OE and Penn transferred their interests to NGC through an asset spin-off in the form of a dividend. On December 28, 2006, the NRC approved the transfer of ownership in NGCregulatory requirements. If actual results differ materially from FirstEnergy to FES. Effective December 31, 2006, NGC is a wholly owned subsidiary of FES and second tier subsidiary of FirstEnergy. FENOC continues to operate and maintain the nuclear generation assets.

Although the generating plant interests transferred in 2005 did not include leasehold interests of CEI, OE and TE in certain of the plants that are subject to sale and leaseback arrangements entered into in 1987 with non-affiliates, effective October 16, 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 13, 2007 Bruce Mansfield Unit 1 sale and leaseback transaction, to a newly formed wholly-owned subsidiary on December 17, 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE remain primarily liable on the 1987 leases and related 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 transactions above were undertaken pursuant to the Ohio Companies and Penns restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required toour assumptions, our costs could be separated from the regulated delivery business of those companies through transfer or sale to a separate corporate entity. The transactions essentially completed the divestitures of owned assets contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants. The transfers were intracompany transactions and, therefore, had no impact on the Company's consolidated results.significantly increased.

~~15. SUPPLEMENTAL GUARANTOR INFORMATION~~

As discussed in Note 6, 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 trusts undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES lease guaranty.

The consolidating statements of income for the three years ended December 31 2007, consolidating balance sheets as of December 31, 2007 and December 31, 2006 and condensed consolidating statements of cash flows for the three years ended December 31, 2007 for FES (parent), 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 the parent’s investment accounts and earnings as if operating lease treatment was achieved (see Note 6). The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

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Our Business is Subject to the Risk that Sensitive Customer Data May be Compromised, Which Could Result in an Adverse Impact to Our Reputation and/or Results of Operations

Our business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business. A security breach may occur, despite security measures taken by us and required of vendors. If a significant or widely publicized breach occurred, our business reputation may be adversely affected, customer confidence may be diminished, or we may become subject to legal claims, fines or penalties, any of which could have a negative impact on our business and/or results of operations.

Acts of War or Terrorism Could Negatively Impact Our Business

The possibility that our infrastructure, such as electric generation, transmission and distribution facilities, or that of an interconnected company, could be direct targets of, or indirect casualties of, an act of war or terrorism, could result in disruption of our ability to generate, purchase, transmit or distribute electricity. Any such disruption could result in a decrease in revenues and additional costs to purchase electricity and to replace or repair our assets, which could have a material adverse impact on our results of operations and financial condition.

Capital Improvements and Construction Projects May Not be Completed Within Forecasted Budget, Schedule or Scope Parameters

Our business plan calls for extensive capital investments, including the installation of environmental control equipment, as well as other initiatives. We may be exposed to the risk of substantial price increases in the costs of labor and materials used in construction. We have engaged numerous contractors and entered into a large number of agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. This could have negative financial impacts such as incurring losses or delays in completing construction projects.

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING CONDENSED STATEMENTS OF INCOME

For the Year Ended December 31, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 4,345,790 $ 1,982,166 $ 1,062,026 $ (3,064,955 ) $ 4,325,027

EXPENSES:
Fuel 26,169 942,946 117,895 - 1,087,010
Purchased power from non-affiliates 764,090 - - - 764,090
Purchased power from affiliates 3,038,786 186,415 73,844 (3,064,955 ) 234,090
Other operating expenses 161,797 352,856 514,389 11,997 1,041,039
Provision for depreciation 2,269 99,741 92,239 (1,337 ) 192,912
General taxes 20,953 41,456 24,689 - 87,098
Total expenses 4,014,064 1,623,414 823,056 (3,054,295 ) 3,406,239

OPERATING INCOME 331,726 358,752 238,970 (10,660 ) 918,788

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees 341,978 4,210 14,880 (308,192 ) 52,876
Interest expense to affiliates (1,320 ) (48,536 ) (15,645 ) - (65,501 )
Interest expense - other (9,503 ) (59,412 ) (39,458 ) 16,174 (92,199 )
Capitalized interest 35 14,369 5,104 - 19,508
Total other income (expense) 331,190 (89,369 ) (35,119 ) (292,018 ) (85,316 )

INCOME BEFORE INCOME TAXES 662,916 269,383 203,851 (302,678 ) 833,472

INCOME TAXES 134,052 90,801 77,467 2,288 304,608

NET INCOME $ 528,864 $ 178,582 $ 126,384 $ (304,966 ) $ 528,864
Changes in Technology may Significantly Affect Our Generation Business by Making Our Generating Facilities Less Competitive

We primarily generate electricity at large central facilities. This method results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies will reduce their costs to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations.

We May Acquire Assets That Could Present Unanticipated Issues for our Business in the Future, Which Could Adversely Affect Our Ability to Realize Anticipated Benefits of Those Acquisitions

Asset acquisitions involve a number of risks and challenges, including: management attention; integration with existing assets; difficulty in evaluating the requirements associated with the assets prior to acquisition, operating costs, potential environmental and other liabilities, and other factors beyond our control; and an increase in our expenses and working capital requirements. Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows or realize other anticipated benefits from any such asset acquisition.

Risks Associated With Regulation

Complex and Changing Government Regulations Could Have a Negative Impact on Our Results of Operations

We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in, or reinterpretations of, existing laws or regulations, or the imposition of new laws or regulations, could require us to incur additional costs or change the way we conduct our business, and therefore could have an adverse impact on our results of operations.

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Our utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. Thus, the rates a utility is allowed to charge may or may not be set to recover its expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered. While rate regulation is premised on providing an opportunity to earn a reasonable return on invested capital and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner.

Regulatory Changes in the Electric Industry, Including a Reversal, Discontinuance or Delay of the Present Trend Toward Competitive Markets, Could Affect Our Competitive Position and Result in Unrecoverable Costs Adversely Affecting Our Business and Results of Operations

As a result of restructuring initiatives, changes in the electric utility business have occurred, and are continuing to take place throughout the United States, including Ohio, Pennsylvania and New Jersey. These changes have resulted, and are expected to continue to result, in fundamental alterations in the way utilities conduct their business.

Some states that have deregulated generation service have experienced difficulty in transitioning to market-based pricing. In some instances, state and federal government agencies and other interested parties have made proposals to delay market restructuring or even re-regulate areas of these markets that have previously been deregulated. Although we expect wholesale electricity markets to continue to be competitive, proposals to re-regulate our industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be delayed, discontinued or reversed in the states in which we currently, or may in the future, operate. Such delays, discontinuations or reversals of electricity market restructuring in the markets in which we operate could have an adverse impact on our results of operations and financial condition.

The FERC and the U.S. Congress propose changes from time to time in the structure and conduct of the electric utility industry. If the restructuring, deregulation or re-regulation efforts result in decreased margins or unrecoverable costs, our business and results of operations would be adversely affected. We cannot predict the extent or timing of further efforts to restructure, deregulate or re-regulate our business or the industry.

The Prospect of Rising Rates Could Prompt Legislative or Regulatory Action to Restrict or Control Such Rate Increases. This In Turn Could Create Uncertainty Affecting Planning, Costs and Results of Operations and May Adversely Affect the Utilities’ Ability to Recover Their Costs, Maintain Adequate Liquidity and Address Capital Requirements

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING CONDENSED STATEMENTS OF INCOME

For the Year Ended December 31, 2006 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 4,023,752 $ 1,767,549 $ 1,028,159 $ (2,808,107 ) $ 4,011,353

EXPENSES:
Fuel 18,265 983,492 103,900 - 1,105,657
Purchased power from non-affiliates 590,491 - - - 590,491
Purchased power from affiliates 2,804,110 180,759 80,239 (2,808,107 ) 257,001
Other operating expenses 202,369 271,718 553,477 - 1,027,564
Provision for depreciation 1,779 93,728 83,656 - 179,163
General taxes 12,459 38,781 22,092 - 73,332
Total expenses 3,629,473 1,568,478 843,364 (2,808,107 ) 3,233,208

OPERATING INCOME 394,279 199,071 184,795 - 778,145

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees 184,267 (596 ) 35,571 (164,740 ) 54,502
Interest expense to affiliates (241 ) (117,639 ) (44,793 ) - (162,673 )
Interest expense - other (720 ) (9,125 ) (16,623 ) - (26,468 )
Capitalized interest 1 4,941 6,553 - 11,495
Total other income (expense) 183,307 (122,419 ) (19,292 ) (164,740 ) (123,144 )

INCOME BEFORE INCOME TAXES 577,586 76,652 165,503 (164,740 ) 655,001

INCOME TAXES 158,933 17,605 59,810 - 236,348

NET INCOME $ 418,653 $ 59,047 $ 105,693 $ (164,740 ) $ 418,653
Increases in utility rates, such as may follow a period of frozen or capped rates, can generate pressure on legislators and regulators to take steps to control those increases. Such efforts can include some form of rate increase moderation, reduction or freeze. The public discourse and debate can increase uncertainty associated with the regulatory process, the level of rates and revenues, and the ability to recover costs. Such uncertainty restricts flexibility and resources, given the need to plan and ensure available financial resources. Such uncertainty also affects the costs of doing business. Such costs could ultimately reduce liquidity, as suppliers tighten payment terms, and increase costs of financing, as lenders demand increased compensation or collateral security to accept such risks.

Our Profitability is Impacted by Our Affiliated Companies’ Continued Authorization to Sell Power at Market-Based Rates

The FERC granted FES, FGCO and NGC authority to sell electricity at market-based rates. These orders also granted them waivers of certain FERC accounting, record-keeping and reporting requirements. The Utilities also have market-based rate authority. The FERC’s orders that grant this market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. As a condition to the orders granting the generating companies market-based rate authority, every three years they are required to file a market power update to show that they continue to meet the FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates. FES, FGCO, NGC and the Utilities renewed this authority for PJM in 2008. Their applications to renew this authorization for MISO are pending at the FERC. If any of these companies were to lose their market-based rate authority or fail to have such authority renewed, it would be required to obtain the FERC’s acceptance to sell power at cost-based rates. FES, FGCO and NGC could also lose their waivers, and become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.

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There Are Uncertainties Relating to Our Participation in Regional Transmission Organizations (RTOs)

RTO rules could affect our ability to sell power produced by our generating facilities to users in certain markets due to transmission constraints and attendant congestion costs. The prices in day-ahead and real-time energy markets and RTO capacity markets have been subject to price volatility. Administrative costs imposed by RTOs, including the cost of administering energy markets, have also increased. The rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. To the degree we incur significant additional fees and increased costs to participate in an RTO, and we are limited with respect to recovery of such costs from retail customers, we may suffer financial harm. While RTO rates for transmission service are designed to be revenue neutral, our revenues from customers to whom we currently provide transmission services may not reflect all of the administrative and market-related costs imposed under the RTO tariff. In addition, we may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. Finally, we may be required to expand our transmission system according to decisions made by an RTO rather than our internal planning process. As a member of an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in that RTO’s market, and those associated with complaint cases filed against the RTO that may seek refunds of revenues previously earned by its members.

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING CONDENSED STATEMENTS OF INCOME

For the Year Ended December 31, 2005 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 3,998,410 $ 1,567,597 $ 671,729 $ (2,270,497 ) $ 3,967,239

EXPENSES:
Fuel 37,955 866,583 101,339 - 1,005,877
Purchased power from non-affiliates 957,570 - - - 957,570
Purchased power from affiliates 2,516,399 60,207 2,493 (2,270,497 ) 308,602
Other operating expenses 276,896 261,646 441,640 - 980,182
Provision for depreciation 1,597 95,237 80,397 - 177,231
General taxes 11,640 37,594 18,068 - 67,302
Total expenses 3,802,057 1,321,267 643,937 (2,270,497 ) 3,496,764

OPERATING INCOME 196,353 246,330 27,792 - 470,475

OTHER INCOME (EXPENSE):
Investment income 4,462 6,964 67,361 - 78,787
Miscellaneous income (expense), including
net income from equity investees 79,371 (2,658 ) (28,000 ) (82,856 ) (34,143 )
Interest expense to affiliates (4,677 ) (102,580 ) (77,060 ) - (184,317 )
Interest expense - other (204 ) (2,220 ) (9,614 ) - (12,038 )
Capitalized interest 82 3,180 11,033 - 14,295
Total other income (expense) 79,034 (97,314 ) (36,280 ) (82,856 ) (137,416 )

INCOME (LOSS) FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES 275,387 149,016 (8,488 ) (82,856 ) 333,059

INCOME TAXES (BENEFIT) 75,630 50,739 (1,870 ) - 124,499

INCOME (LOSS) FROM CONTINUING OPERATIONS 199,757 98,277 (6,618 ) (82,856 ) 208,560

Discontinued operations (net of income taxes of $3,761,000) 5,410 - - - 5,410

INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE 205,167 98,277 (6,618 ) (82,856 ) 213,970

Cumulative effect of a change in accounting principle (net
of income tax benefit of $5,507,000) - (8,803 ) - - (8,803 )

NET INCOME (LOSS) $ 205,167 $ 89,474 $ (6,618 ) $ (82,856 ) $ 205,167

MISO implemented an ancillary services market for operating reserves that would be simultaneously co-optimized with MISO's existing energy markets. The implementation of these and other new market designs has the potential to increase our costs of transmission, costs associated with inefficient generation dispatching, costs of participation in the market and costs associated with estimated payment settlements.

Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will ultimately develop and operate, or what region they will cover, we cannot fully assess the impact that these power markets or other ongoing RTO developments may have.

Energy Conservation and Energy Price Increases Could Negatively Impact our Financial Results

A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce energy consumption by certain dates. Conservation programs could impact our financial results in different ways. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of our merchant generation and other unregulated business activities could be adversely impacted. In our regulated operations, conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. We could also be impacted if any future energy price increases result in a decrease in customer usage. We are unable to determine what impact, if any, conservation and increases in energy prices will have on our financial condition or results of operations.

Our Business and Activities are Subject to Extensive Environmental Requirements and Could be Adversely Affected by such Requirements

We may be forced to shut down facilities, either temporarily or permanently, if we are unable to comply with certain environmental requirements, or if we make a determination that the expenditures required to comply with such requirements are uneconomical. In fact, we are exposed to the risk that such electric generating plants would not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines.

Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with Future Environmental Laws, Including Limitations on GHG Emissions Could Adversely Affect Cash Flow and Profitability

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for environmental monitoring, installation of pollution control equipment, emission fees, maintenance, upgrading, remediation and permitting at our facilities. These expenditures have been significant in the past and may increase in the future. If the cost of compliance with existing environmental laws and regulations does increase, it could adversely affect our business and results of operations, financial position and cash flows. Moreover, changes in environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures. Because of the deregulation of generation, we may not directly recover through rates additional costs incurred for such compliance. Our compliance strategy, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control or new interpretations of longstanding requirements, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. Environmental advocacy groups, other organizations and some agencies in the United States are focusing considerable attention on carbon dioxide emissions from power generation facilities and their potential role in climate change. Many states and environmental groups have also challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict. There is a growing consensus in the United States and globally that GHG emissions are a major cause of global warming and that some form of regulation will be forthcoming at the federal level with respect to GHG emissions (including carbon dioxide) and such regulation could result in the creation of substantial additional costs in the form of taxes or emission allowances. As a result, it is possible that state and federal regulations will be developed that will impose more stringent limitations on emissions than are currently in effect. Although several bills have been introduced at the state and federal level that would compel carbon dioxide emission reductions, none have advanced through the legislature. Such legislation could even make some of our electric generating units uneconomic to maintain or operate. Due to the uncertainty of control technologies available to reduce greenhouse gas emissions including CO2, as well as the unknown nature of potential compliance obligations should climate change regulations be enacted, we cannot provide any assurance regarding the potential impacts these future regulations would have on our operations. In addition, any legal obligation that would require us to substantially reduce our emissions could require extensive mitigation efforts and, in the case of carbon dioxide legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. Until specific regulations are promulgated, the impact that any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation may have on our results of operations, financial condition or liquidity is not determinable.

The EPA’s current CAIR and CAVR require significant reductions beginning in 2009 in air emissions from coal-fired power plants and the states have been given substantial discretion in developing their own rules to implement these programs. On December 23, 2008, the United States Court of Appeals for the District of Columbia remanded CAIR to EPA but allowed the current CAIR regulations to remain in effect while EPA works to remedy flaws in the CAIR regulations identified by the court in a July 11, 2008 opinion. As a result, the ultimate requirements under CAIR may not be known for several years and may differ significantly from the current CAIR regulations. If the EPA significantly changes CAIR, or if the states elect to impose additional requirements on individual units that are already subject to CAIR, the cost of compliance could increase significantly and could have an adverse effect on future results of operations, cash flows and financial condition.

The EPA's final CAMR was vacated by the United States Court of Appeals for the District Court of Columbia on February 8, 2008 because the EPA failed to take the necessary steps to "de-list" coal-fired power plants from its hazardous air pollution program and therefore could not promulgate a cap and trade air emissions reduction program. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the United States moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the United States’ petition and denied the industry group’s petition. Accordingly, the EPA could take regulatory action to promulgate new mercury emission standards for coal-fired power plants. As a result of further regulatory action by the EPA, the cost of compliance could increase significantly and could have a material adverse effect on future results of operations, cash flows and financial condition.

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to our generating plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to our 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.

There is substantial uncertainty concerning the final form of federal and state regulations to implement Section 316(b) of the Clean Water Act. On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded back to the EPA portions of its rulemaking pursuant to Section 316(b). The EPA subsequently suspended its 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 decision. Oral argument before the Supreme Court occurred on December 2, 2008 and a decision is anticipated during the first half of 2009. Depending on the outcome of the Supreme Court’s review and the nature of the final regulations that may ultimately be adopted by the EPA, we may incur significant capital costs to comply with the final regulations. If either the federal or state final regulations require retrofitting of cooling water intake structures (cooling towers) at any of our power plants, and if installation of such cooling towers is not technically or economically feasible, we may be forced to take actions which could adversely impact our results of operations and financial condition.

Remediation of Environmental Contamination at Current or Formerly Owned Facilities

We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. Remediation activities associated with our former MGP operations are one source of such costs. We are currently involved in a number of proceedings relating to sites where other hazardous substances have been deposited and may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material.

In some cases, a third party who has acquired assets from us has assumed the liability we may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.

Availability and Cost of Emission Credits Could Materially Impact Our Costs of Operations

We are required to maintain, either by allocation or purchase, sufficient emission credits to support our operations in the ordinary course of operating our power generation facilities. These credits are used to meet our obligations imposed by various applicable environmental laws. If our operational needs require more than our allocated allowances of emission credits, we may be forced to purchase such credits on the open market, which could be costly. If we are unable to maintain sufficient emission credits to match our operational needs, we may have to curtail our operations so as not to exceed our available emission credits, or install costly new emissions controls. As we use the emissions credits that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such credits are available for purchase, but only at significantly higher prices, the purchase of such credits could materially increase our costs of operations in the affected markets.

Mandatory Renewable Portfolio Requirements Could Negatively Affect Our Costs

If federal or state legislation mandates the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal, and such legislation would not also provide for adequate cost recovery, it could result in significant changes in our business, including renewable energy credit purchase costs, purchased power and potentially renewable energy credit costs and capital expenditures. We are unable to predict what impact, if any, these changes may have on our financial condition or results of operations.

We Are and May Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of our Facilities

We have been named as a defendant in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at our facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us.

The Continuing Availability and Operation of Generating Units is Dependent on Retaining the Necessary Licenses, Permits, and Operating Authority from Governmental Entities, Including the NRC

We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of any of these agencies and we are not assured that any such permits, approvals or certifications will be renewed.

Future Changes in Financial Accounting Standards May Affect Our Reported Financial Results

The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially impact how we report our financial condition and results of operations. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial position. The SEC has issued a roadmap for the transition by U.S. public companies to the use of International Financial Reporting Standards (IFRS) promulgated by the International Accounting Standards Board. Under the SEC’s proposed roadmap, we could be required in 2014 to prepare financial statements in accordance with IFRS. The SEC expects to make a determination in 2011 regarding the mandatory adoption of IFRS. We are currently assessing the impact that this potential change would have on our consolidated financial statements and we will continue to monitor the development of the potential implementation of IFRS.

Risks Associated With Financing and Capital Structure

Interest Rates and/or a Credit Rating Downgrade Could Negatively Affect Our Financing Costs, Our Ability to Access Capital and Our Requirement to Post Collateral

We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. The recent disruptions in capital and credit markets have resulted in higher interest rates on new publicly issued debt securities, increased costs for certain of our variable interest rate debt securities and failed remarketings (all of which were eventually remarketed) of variable interest rate tax-exempt debt issued to finance certain of our facilities. Continuation of these disruptions could increase our financing costs and adversely affect our results of operations. Also, interest rates could change as a result of economic or other events that our risk management processes were not established to address. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations.

We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. A downgrade in our credit ratings from the nationally recognized credit rating agencies, particularly to a level below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as available letters of credit and other guarantees. A rating downgrade would also increase the fees we pay on our various credit facilities, thus increasing the cost of our working capital. A rating downgrade could also impact our ability to grow our businesses by substantially increasing the cost of, or limiting access to, capital. Our senior unsecured debt ratings from S&P and Moody’s are investment grade. The current ratings outlook from S&P and Moody’s is stable.

A rating is not a recommendation to buy, sell or hold debt, inasmuch as such rating does not comment as to market price or suitability for a particular investor. The ratings assigned to our debt address the likelihood of payment of principal and interest pursuant to their terms. A rating may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating that may be assigned to our securities. Also, we cannot predict how rating agencies may modify their evaluation process or the impact such a modification may have on our ratings.

Our credit ratings also govern the collateral provisions of certain contract guarantees. Subsequent to the occurrence of a credit rating downgrade to below investment grade or a “material adverse event,” the immediate posting of cash collateral may be required. See Note 14(B) of the Notes to the Consolidated Financial Statements for more information associated with a credit ratings downgrade leading to the posting of cash collateral.

We Must Rely on Cash from Our Subsidiaries and Any Restrictions on Our Utility Subsidiaries’ Ability to Pay Dividends or Make Cash Payments to Us May Adversely Affect Our Financial Condition

We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our business is conducted by our subsidiaries. Consequently, our cash flow is dependent on the operating cash flows of our subsidiaries and their ability to upstream cash to the holding company. Our utility subsidiaries are regulated by various state utility commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state commissions could attempt to impose restrictions on the ability of our utility subsidiaries to pay dividends or otherwise restrict cash payments to us.

We Cannot Assure Common Shareholders that Future Dividend Payments Will be Made, or if Made, in What Amounts they May be Paid

Our Board of Directors regularly evaluates our common stock dividend policy and determines the dividend rate each quarter. The level of dividends will continue to be influenced by many factors, including, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past.

Disruptions in the Capital and Credit Markets May Adversely Affect our Business, Including the Availability and Cost of Short-Term Funds for Liquidity Requirements, Our Ability to Meet Long-Term Commitments, our Ability to Hedge Effectively our Generation Portfolio, and the Competitiveness and Liquidity of Energy Markets; Each Could Adversely Affect our Results of Operations, Cash Flows and Financial Condition

We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit provided by various financial institutions to support our hedging operations. Disruptions in the capital and credit markets, as have been experienced during 2008, could adversely affect our ability to draw on our respective credit facilities. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time.

Longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our business. Any disruption could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.

The strength and depth of competition in energy markets depends heavily on active participation by multiple counterparties, which could be adversely affected by disruptions in the capital and credit markets. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on our results of operations and cash flows.

Questions Regarding the Soundness of Financial Institutions or Counterparties Could Adversely Affect Us

We have exposure to many different financial institutions and counterparties and we routinely execute transactions with counterparties in connection with our hedging activities, including brokers and dealers, commercial banks, investment banks and other institutions and industry participants. Many of these transactions expose us to credit risk in the event that any of our lenders or counterparties are unable to honor their commitments or otherwise default under a financing agreement. We also deposit cash balances in short-term investments. Our ability to access our cash quickly depends on the soundness of the financial institutions in which those funds reside. Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.

Our Electric Utility Operating Affiliates in Ohio are Currently in the Midst of Rate Proceedings that have the Potential to Adversely Affect Our Financial Condition

As required by Amended Substitute Senate Bill 221 (SB221), Ohio’s new electricity restructuring law, our Ohio utility subsidiaries filed on July 31, 2008 with the PUCO a comprehensive ESP and an MRO. The ESP proposed, among other things, to phase in new generation rates for customers beginning in 2009 for up to a three-year period and to resolve a then pending distribution rate increase request. The MRO filing outlined a competitive bid process for providing retail generation supply at market prices in accordance with SB221 if the ESP was not approved and implemented by our Ohio utilities. The PUCO rejected the MRO filing on November 25, 2008 and we filed an application for rehearing on December 22, 2008.

The PUCO modified the ESP on December 19, 2008. We withdrew the ESP as so modified on December 22, 2008 opting instead to keep the current rate plan in effect, as we believe SB221 requires. Because our Ohio utilities do not own generating plants, they subsequently completed a competitive procurement process to ensure a reliable supply of electricity, for customers who do not shop, for the period January 5, 2009 through March 31, 2009.

Subsequent to the competitive procurement process, the PUCO ruled that our Ohio utilities could not continue certain portions of their existing tariffs. Citing inconsistencies with Ohio law and potentially serious financial consequences that could result from the PUCO’s ruling, on January 9, 2009, we filed a motion to stay, as well as an application for rehearing and an application for a fuel rider. On January 9, 2009, an order was entered permitting our Ohio utilities to continue charging current rates until the PUCO rules on the pending filings. On January 14, 2009, the PUCO approved our Ohio utilities’ application to recover fuel and associated purchased power costs during the period January 1, 2009 through March 31, 2009 subject to review by the PUCO, and affirmed its January 9, 2009 order regarding our Ohio utilities’ ability to continue charging specific components of current rates.

Substantial recovery under the fuel rider is necessary to ensure that our Ohio utilities recover costs related to their provider-of-last-resort obligation to their customers. Without such recovery, providing generation service to their customers at rates that are well below actual costs would cause them to incur a cash shortfall of approximately $2 million per day. This could require our Ohio Utilities to make immediate and severe reductions in operating and capital expenditures and could have other material adverse impacts on the financial condition and results of operations of not only our Ohio utilities but also FirstEnergy. Any resulting deterioration in our financial metrics could result in a downgrade of our credit ratings.On January 21, 2009, the PUCO granted our Ohio utilities’ application for an increase in distribution rates in the amount of $136.6 million in the aggregate for all three companies, as well as the application for rehearing of the MRO filing.

On February 19, 2009, the Ohio Companies filed an application for an amended ESP which substantially reflected the terms proposed by PUCO Staff to resolve the ESP proceeding, which the PUCO attorney examiner set for a hearing to begin on February 25, 2009 (see Regulatory Matters – Ohio).

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

The Utilities’ and FGCO’s respective first mortgage indentures constitute, in the opinion of their counsel, direct first liens on substantially all of the respective Utilities’ and FGCO’s physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. See the “Leases” and “Capitalization” notes to the respective financial statements for information concerning leases and financing encumbrances affecting certain of the Utilities’ and FGCO’s properties.

FirstEnergy has access, either through ownership or lease, to the following generation sources as of February 25, 2009, shown in the table below. Except for the leasehold interests and OVEC participation referenced in the footnotes to the table, substantially all of the generating units are owned by NGC (nuclear) and FGCO (non-nuclear). See "Generation Asset Transfers" under Item 1 above.

			Net
			Demonstrated
			Capacity
	Unit		(MW)
Plant-Location
Coal-Fired Units
Ashtabula-
Ashtabula, OH		5		244
Bay Shore-
Toledo, OH		1-4		631
R. E. Burger-
Shadyside, OH		3-5		406
Eastlake-Eastlake, OH		1-5		1,233
Lakeshore-
Cleveland, OH		18		245
Bruce Mansfield-		1		830	(a)
Shippingport, PA		2		830	(b)
		3		830	(c)
W. H. Sammis - Stratton, OH		1-7		2,220
Kyger Creek - Cheshire, OH		1-5		210	(d)
Clifty Creek - Madison, IN		1-6		253	(d)
Total				7,932

Nuclear Units
Beaver Valley-		1		911
Shippingport, PA		2		904	(e)
Davis-Besse-
Oak Harbor, OH		1		908
Perry-
N. Perry Village, OH		1		1,268	(f)
Total				3,991

Oil/Gas - Fired/
Pumped Storage Units
Richland - Defiance, OH		1-6		432
Seneca - Warren, PA		1-3		451
Sumpter - Sumpter Twp, MI		1-4		340
West Lorain - Lorain, OH		1-6		545
Yard’s Creek - Blairstown
Twp., NJ		1-3		200	(g)
Other				282
Total				2,250
Total				14,173

Notes:	(a)	Includes FGCO’s leasehold interest of 93.825% (779 MW) and CEI’s leasehold interest of 6.175% (51 MW), which has been assigned to FGCO.
	(b)	Includes CEI’s and TE’s leasehold interests of 27.17% (226 MW) and 16.435% (136 MW), respectively, which have been assigned to FGCO.
	(c)	Includes CEI’s and TE’s leasehold interests of 23.247% (193 MW) and 18.915% (157 MW), respectively, which have been assigned to FGCO.
	(d)	Represents FGCO’s 20.5% entitlement based on its participation in OVEC. FGCO has entered into a definitive agreement to sell 9% of its 20.5% participation in OVEC. Final closing of the transaction, which is expected in April 2009, is subject to approval by the FERC.
	(e)	Includes OE’s leasehold interest of 16.65% (151 MW) from non-affiliates.
	(f)	Includes OE’s leasehold interest of 8.11% (103 MW) from non-affiliates.
	(g)	Represents JCP&L’s 50% ownership interest.

The above generating plants and load centers are connected by a transmission system consisting of elements having various voltage ratings ranging from 23 kV to 500 kV. The Utilities’ overhead and underground transmission lines aggregate 15,070 pole miles.

7737

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents $ 2 $ - $ - $ - $ 2
Receivables-
Customers 133,846 - - - 133,846
Associated companies 327,715 237,202 98,238 (286,656 ) 376,499
Other 2,845 978 - - 3,823
Notes receivable from associated companies 23,772 - 69,012 - 92,784
Materials and supplies, at average cost 195 215,986 210,834 - 427,015
Prepayments and other 67,981 21,605 2,754 - 92,340
556,356 475,771 380,838 (286,656 ) 1,126,309

PROPERTY, PLANT AND EQUIPMENT:
In service 25,513 5,065,373 3,595,964 (392,082 ) 8,294,768
Less - Accumulated provision for depreciation 7,503 2,553,554 1,497,712 (166,756 ) 3,892,013
18,010 2,511,819 2,098,252 (225,326 ) 4,402,755
Construction work in progress 1,176 571,672 188,853 - 761,701
19,186 3,083,491 2,287,105 (225,326 ) 5,164,456

INVESTMENTS:
Nuclear plant decommissioning trusts - - 1,332,913 - 1,332,913
Long-term notes receivable from associated companies - - 62,900 - 62,900
Investment in associated companies 2,516,838 - - (2,516,838 ) -
Other 2,732 37,071 201 - 40,004
2,519,570 37,071 1,396,014 (2,516,838 ) 1,435,817

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes 16,978 522,216 - (262,271 ) 276,923
Lease assignment receivable from associated companies - 215,258 - - 215,258
Goodwill 24,248 - - - 24,248
Property taxes - 25,007 22,767 - 47,774
Pension asset 3,217 13,506 - - 16,723
Unamortized sale and leaseback costs - 27,597 - 43,206 70,803
Other 22,956 52,971 6,159 (38,133 ) 43,953
67,399 856,555 28,926 (257,198 ) 695,682
TOTAL ASSETS $ 3,162,511 $ 4,452,888 $ 4,092,883 $ (3,286,018 ) $ 8,422,264

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt $ - $ 596,827 $ 861,265 $ (16,896 ) $ 1,441,196
Short-term borrowings-
Associated companies - 238,786 25,278 264,064
Other 300,000 - - - 300,000
Accounts payable-
Associated companies 287,029 175,965 268,926 (286,656 ) 445,264
Other 56,194 120,927 - - 177,121
Accrued taxes 18,831 125,227 28,229 (836 ) 171,451
Other 57,705 131,404 11,972 36,725 237,806
719,759 1,389,136 1,195,670 (267,663 ) 3,036,902

CAPITALIZATION:
Common stockholder's equity 2,414,231 951,542 1,562,069 (2,513,611 ) 2,414,231
Long-term debt - 1,597,028 242,400 (1,305,716 ) 533,712
2,414,231 2,548,570 1,804,469 (3,819,327 ) 2,947,943

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction - - - 1,060,119 1,060,119
Accumulated deferred income taxes - - 259,147 (259,147 ) -
Accumulated deferred investment tax credits - 36,054 25,062 - 61,116
Asset retirement obligations - 24,346 785,768 - 810,114
Retirement benefits 8,721 54,415 - - 63,136
Property taxes - 25,328 22,767 - 48,095
Lease market valuation liability - 353,210 - - 353,210
Other 19,800 21,829 - - 41,629
28,521 515,182 1,092,744 800,972 2,437,419
TOTAL LIABILITIES AND CAPITALIZATION $ 3,162,511 $ 4,452,888 $ 4,092,883 $ (3,286,018 ) $ 8,422,264
The Utilities’ electric distribution systems include 118,562 miles of overhead pole line and underground conduit carrying primary, secondary and street lighting circuits. They own substations with a total installed transformer capacity of 87,624,000 kV-amperes.

The transmission facilities that are owned by ATSI are operated on an integrated basis as part of MISO and are interconnected with facilities operated by PJM. The transmission facilities of JCP&L, Met-Ed and Penelec are physically interconnected and are operated on an integrated basis as part of PJM.

FirstEnergy’s distribution and transmission systems as of December 31, 2008, consist of the following:

					Substation
	Distribution		Transmission		Transformer
	Lines		Lines		Capacity
	(Miles)				(kV-amperes)

OE		30,413		555		9,718,000
Penn		5,911		44		922,000
CEI		25,321		2,144		7,841,000
TE		2,083		224		2,503,000
JCP&L		19,604		2,160		21,216,000
Met-Ed		15,057		1,421		9,962,000
Penelec		20,173		2,701		14,033,000
ATSI*		-		5,821		21,429,000
Total		118,562		15,070		87,624,000

Represents transmission lines of 69kV and above located in the service areas of OE, Penn, CEI and TE.

ITEM 3. LEGAL PROCEEDINGS

Reference is made to Note 14, Commitments, Guarantees and Contingencies, of FirstEnergy’s Notes to Consolidated Financial Statements contained in Item 8 for a description of certain legal proceedings involving FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The information required by Item 5 regarding FirstEnergy’s market information, including stock exchange listings and quarterly stock market prices, dividends and holders of common stock is included on page 1 of FirstEnergy’s 2008 Annual Report to Stockholders (Exhibit 13.1). Pursuant to General Instruction I of Form 10-K, information for FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec is not required to be disclosed because they are wholly owned subsidiaries.

Information regarding compensation plans for which shares of FirstEnergy common stock may be issued is incorporated herein by reference to FirstEnergy’s 2009 proxy statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.

7838

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2006 FES FGCO NGC Eliminations Consolidated
(In thousands)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents $ 2 $ - $ - $ - $ 2
Receivables-
Customers 129,843 - - - 129,843
Associated companies 201,281 160,965 69,751 (196,465 ) 235,532
Other 2,383 1,702 - - 4,085
Notes receivable from associated companies 460,023 - 292,896 - 752,919
Materials and supplies, at average cost 195 238,936 221,108 - 460,239
Prepayments and other 45,314 10,389 1,843 - 57,546
839,041 411,992 585,598 (196,465 ) 1,640,166

PROPERTY, PLANT AND EQUIPMENT:
In service 16,261 4,960,453 3,378,630 - 8,355,344
Less - Accumulated provision for depreciation 5,738 2,477,004 1,335,526 - 3,818,268
10,523 2,483,449 2,043,104 - 4,537,076
Construction work in progress 345 170,063 169,478 - 339,886
10,868 2,653,512 2,212,582 - 4,876,962

INVESTMENTS:
Nuclear plant decommissioning trusts - - 1,238,272 - 1,238,272
Long-term notes receivable from associated companies - - 62,900 - 62,900
Investment in associated companies 1,471,184 - - (1,471,184 ) -
Other 6,474 65,833 202 - 72,509
1,477,658 65,833 1,301,374 (1,471,184 ) 1,373,681

DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 24,248 - - - 24,248
Property taxes - 20,946 23,165 - 44,111
Accumulated deferred income taxes 32,939 - - (32,939 ) -
Other 23,544 11,542 4,753 - 39,839
80,731 32,488 27,918 (32,939 ) 108,198
TOTAL ASSETS $ 2,408,298 $ 3,163,825 $ 4,127,472 $ (1,700,588 ) $ 7,999,007

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt $ - $ 608,395 $ 861,265 $ - $ 1,469,660
Notes payable to associated companies - 1,022,197 - - 1,022,197
Accounts payable-
Associated companies 375,328 11,964 365,222 (196,465 ) 556,049
Other 32,864 103,767 - - 136,631
Accrued taxes 54,537 32,028 26,666 - 113,231
Other 49,906 41,401 9,634 - 100,941
512,635 1,819,752 1,262,787 (196,465 ) 3,398,709

CAPITALIZATION:
Common stockholder's equity 1,859,363 78,542 1,392,642 (1,471,184 ) 1,859,363
Long-term debt - 1,057,252 556,970 - 1,614,222
1,859,363 1,135,794 1,949,612 (1,471,184 ) 3,473,585

NONCURRENT LIABILITIES:
Accumulated deferred income taxes - 25,293 129,095 (32,939 ) 121,449
Accumulated deferred investment tax credits - 38,894 26,857 - 65,751
Asset retirement obligations - 24,272 735,956 - 760,228
Retirement benefits 10,255 92,772 - - 103,027
Property taxes - 21,268 23,165 - 44,433
Other 26,045 5,780 - - 31,825
36,300 208,279 915,073 (32,939 ) 1,126,713
TOTAL LIABILITIES AND CAPITALIZATION $ 2,408,298 $ 3,163,825 $ 4,127,472 $ (1,700,588 ) $ 7,999,007
The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock during the fourth quarter of 2008.

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Year Ended December 31, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)

NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES $ (18,017 ) $ 55,172 $ 263,468 $ (6,306 ) $ 294,317

CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt - 1,576,629 179,500 (1,328,919 ) 427,210
Equity contribution from parent
700,000 700,000 - (700,000 ) 700,000
Short-term borrowings, net 300,000 - 25,278 (325,278 ) -
Redemptions and repayments-
Common stock (600,000 ) - - - (600,000 )
Long-term debt - (1,052,121 ) (495,795 ) 6,306 (1,541,610 )
Short-term borrowings, net - (783,599 ) - 325,278 (458,321 )
Common stock dividend payments (117,000 ) - - - (117,000 )
Net cash provided from (used for) financing activities 283,000 440,909 (291,017 ) (2,022,613 ) (1,589,721 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (10,603 ) (502,311 ) (225,795 ) - (738,709 )
Proceeds from asset sales - 12,990 - - 12,990
Proceeds from sale and leaseback transaction - - - 1,328,919 1,328,919
Sales of investment securities held in trusts - - 655,541 - 655,541
Purchases of investment securities held in trusts - - (697,763 ) - (697,763 )
Loans to associated companies 441,966 - 292,896 - 734,862
Investment in subsidiary (700,000 ) - - 700,000 -
Other 3,654 (6,760 ) 2,670 - (436 )
Net cash provided from (used for) investing activities (264,983 ) (496,081 ) 27,549 2,028,919 1,295,404

Net change in cash and cash equivalents - - - - -
Cash and cash equivalents at beginning of year 2 - - - 2
Cash and cash equivalents at end of year $ 2 $ - $ - $ - $ 2

	Period
	October		November		December		Fourth Quarter
Total Number of Shares Purchased(a)		22,317		44,129		253,936		320,382
Average Price Paid per Share	$	54.66	$	54.39	$	55.94	$	55.64
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		-		-		-		-
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs		-		-		-		-
(a) Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan, and shares purchased as part of publicly announced plans.

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Year Ended December 31, 2006 FES FGCO NGC Eliminations Consolidated
(In thousands)

NET CASH PROVIDED FROM OPERATING ACTIVITIES $ 250,518 $ 150,510 $ 470,578 $ (12,765 ) $ 858,841

CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt - 565,326 591,515 - 1,156,841
Short-term borrowings, net - 46,402 - - 46,402
Redemptions and repayments-
Long-term debt - (543,064 ) (594,676 ) - (1,137,740 )
Dividend payments
Common stock (8,454 ) - (12,765 ) 12,765 (8,454 )
Net cash provided from (used for) financing activities (8,454 ) 68,664 (15,926 ) 12,765 57,049

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (948 ) (212,867 ) (363,472 ) - (577,287 )
Proceeds from asset sales - 34,215 - - 34,215
Sales of investment securities held in trusts - - 1,066,271 - 1,066,271
Purchases of investment securities held in trusts - - (1,066,271 ) - (1,066,271 )
Loans to associated companies (242,597 ) - (90,433 ) - (333,030 )
Other 1,481 (40,522 ) (747 ) - (39,788 )
Net cash used for investing activities (242,064 ) (219,174 ) (454,652 ) - (915,890 )

Net change in cash and cash equivalents - - - - -
Cash and cash equivalents at beginning of year 2 - - - 2
Cash and cash equivalents at end of year $ 2 $ - $ - $ - $ 2
ITEM 6. SELECTED FINANCIAL DATA

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by Items 6 through 8 is incorporated herein by reference to Selected Financial Data, Management’s Discussion and Analysis of Financial Condition and Results of Operation, and Financial Statements included on the following pages in the 2008 Annual Report of FirstEnergy (Exhibit 13.1) and the combined 2008 Annual Report of FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec (Exhibit 13.2).

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Year Ended December 31, 2005 FES FGCO NGC Eliminations Consolidated
(In thousands)

NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES $ 475,191 $ 243,683 $ (71,526 ) $ - $ 647,348

CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Short-term borrowings, net - 130,876 - (130,876 ) -
Equity contribution from parent 262,200 - 459,498 (459,498 ) 262,200
Redemptions and repayments-
Short-term borrowings, net (245,215 ) - - 130,876 (114,339 )
Return of capital to parent - (197,298 ) 197,298 -
Net cash provided from (used for) financing activities 16,985 (66,422 ) 459,498 (262,200 ) 147,861

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (1,340 ) (186,176 ) (224,044 ) - (411,560 )
Proceeds from asset sales 15,000 43,087 - - 58,087
Sales of investment securities held in trusts - - 1,097,276 - 1,097,276
Purchases of investment securities held in trusts - - (1,186,381 ) - (1,186,381 )
Loans to associated companies (217,426 ) - (74,200 ) - (291,626 )
Return of capital from subsidiary 197,298 - - (197,298 ) -
Investment in subsidiary (459,498 ) - - 459,498 -
Other (26,211 ) (34,199 ) (623 ) - (61,033 )
Net cash used for investing activities (492,177 ) (177,288 ) (387,972 ) 262,200 (795,237 )

Net change in cash and cash equivalents (1 ) (27 ) - - (28 )
Cash and cash equivalents at beginning of year 3 27 - - 30
Cash and cash equivalents at end of year $ 2 $ - $ - $ - $ 2

	Item 6*	Item 7*	Item 7A	Item 8

FirstEnergy	1-2	3-59	38-41	62-109
FES	N/A	N/A	3-5	8-12, 91-145
OE	N/A	N/A	14-15	18-22, 91-145
CEI	N/A	N/A	24-25	28-32, 91-145
TE	N/A	N/A	35	38-42, 91-145
JCP&L	N/A	N/A	44-46	49-53, 91-145
Met-Ed	N/A	N/A	55-57	60-64, 91-145
Penelec	N/A	N/A	66-68	71-75, 91-145

*FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to Form 10-K.

~~16.~~ ~~NEW ACCOUNTING STANDARDS AND INTERPRETATIONS~~

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

~~SFAS 157 - "Fair Value Measurements"~~None.

In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value, which focuses on an exit price rather than entry price; (2) the methods used to measure fair value, such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement and its related FSPs are effective for fiscal years beginning after November 15, 2007, and interim periods within those years. Under FSP FAS 157-2, FES and the Companies have elected to defer the election of SFAS 157 for financial assets and financial liabilities measured at fair value on a non-recurring basis for one year. FES and the Companies have evaluated the impact of this Statement and its FSPs, FAS 157-2 and FSP FAS 157-1, which excludes SFAS 13, ~~Accounting for Leases,~~ and its related pronouncements from the scope of SFAS 157, and are not expecting there to be a material effect on their financial statements. The majority of the FES and the Companies fair value measurements will be disclosed as level 1 or level 2 in the fair value hierarchy.

~~SFAS 159 - "The Fair Value Option for Financial Assets and Financial Liabilities Including an amendment of FASB Statement No. 115"~~

In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and financial liabilities at fair value. This Statement attempts to provide additional information that will help investors and other users of financial statements to more easily understand the effect of a company's choice to use fair value on its earnings. The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157 and SFAS 107. This Statement is effective for fiscal years beginning after November 15, 2007, and interim periods within those years. FES and the Companies have analyzed their financial assets and financial liabilities within the scope of this Statement and no fair value elections were made as of January 1, 2008.

~~SFAS 141(R) - "Business Combinations"~~

In December 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and 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. SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. 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 impact business combinations entered into by FES and the Companies that close after January 1, 2009 and is not expected to have a material impact on FES and the Companies financial statements.

~~SFAS 160 - "Noncontrolling 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 FES and the Companies financial statements.

~~FSP FIN 39-1 - "Amendment of FASB Interpretation No. 39"~~

In April 2007, the FASB issued Staff Position (FSP) FIN 39-1, which permits an entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement as the derivative instruments. This FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. The effects of applying the guidance in this FSP should be recognized as a retrospective change in accounting principle for all financial statements presented. FSP FIN 39-1 is not expected to have a material effect on FES and the Companies financial statements.

~~EITF 06-11 - "Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards"~~

In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R). The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to APIC. This amount should be included in the APIC pool, which is to be used when an entitys estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement. The consensus is effective for income tax benefits of dividends declared during fiscal years beginning after December 15, 2007. EITF 06-11 is not expected to have a material effect on FES and the Companies' financial statements.

~~17. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)~~

~~The following summarizes certain consolidated operating results by quarter for 2007 and 2006.~~

Income (Loss)
From Continuing
Operating Operations
Income Before Income Net
Three Months Ended Revenues (Loss) Income Taxes Taxes Income
(In millions)

FES

March 31, 2007 $ 1018.2 $ 188.7 $ 164.9 $ 62.4 $ 102.5
March 31, 2006 956.5 89.7 56.6 19.4 37.2
June 30, 2007 1068.7 263.8 239.1 87.7 151.4
June 30, 2006 994.0 192.2 157.6 59.0 98.6
September 30,2007 1170.1 272.1 248.4 93.7 154.8
September 30,2006 1109.6 301.6 282.4 106.2 176.2
December 31, 2007 1068.0 194.2 181.1 60.8 120.2
December 31, 2006 951.2 194.6 158.4 51.7 106.7

OE

March 31, 2007 $ 625.6 $ 65.4 $ 71.5 $ 17.4 $ 54.0
March 31, 2006 586.2 86.8 102.1 38.3 63.8
June 30, 2007 596.8 70.8 73.2 27.6 45.7
June 30, 2006 573.1 79.3 94.2 35.0 59.2
September 30,2007 668.8 82.0 82.3 34.1 48.2
September 30,2006 673.7 50.8 61.4 17.9 43.5
December 31, 2007 600.3 73.1 71.4 22.2 49.3
December 31, 2006 594.5 74.2 77.2 32.1 45.1

CEI

March 31, 2007 $ 440.8 $ 115.5 $ 98.3 $ 34.8 $ 63.5
March 31, 2006 407.8 124.3 116.9 44.5 72.4
June 30, 2007 449.5 128.6 111.0 42.1 68.9
June 30, 2006 432.4 152.3 148.8 57.7 91.1
September 30,2007 529.1 154.4 133.3 54.6 78.7
September 30,2006 515.9 140.3 131.9 48.5 83.4
December 31, 2007 403.5 113.7 97.2 31.9 65.3
December 31, 2006 413.6 109.7 97.1 38.0 59.1

TE

March 31, 2007 $ 240.5 $ 40.3 $ 37.0 $ 11.1 $ 25.9
March 31, 2006 218.0 43.2 46.2 17.2 29.0
June 30, 2007 240.3 40.8 37.3 15.4 21.9
June 30, 2006 225.6 49.3 52.3 19.9 32.4
September 30,2007 269.7 47.5 43.5 18.4 25.1
September 30,2006 262.8 43.7 46.8 17.7 29.1
December 31, 2007 213.4 28.8 27.2 8.8 18.3
December 31, 2006 221.6 14.3 13.9 5.1 8.8

Income (Loss)
From Continuing
Operating Operations Net
Income Before Income Income
Three Months Ended
Revenues (Loss) Income Taxes Taxes (Loss)
(In millions)
Met-Ed
March 31, 2007 $ 370.3 $ 57.9 $ 55.2 $ 23.6 $ 31.6
March 31, 2006 311.2 28.7 29.1 11.2 17.9
June 30, 2007 361.7 38.0 34.3 14.8 19.5
June 30, 2006 282.2 70.6 69.6 29.5 40.1
September 30,2007 410.6 43.8 39.4 14.7 24.7
September 30,2006 356.2 42.0 39.6 14.6 25.0
December 31, 2007 367.9 45.3 34.8 15.2 19.7
December 31, 2006 * 293.5 (300.2 ) (301.2 ) 22.0 (323.2 )

Penelec
March 31, 2007 $ 355.9 $ 65.7 $ 56.0 $ 24.3 $ 31.7
March 31, 2006 291.8 45.0 37.1 14.0 23.1
June 30, 2007 331.4 44.5 33.8 14.4 19.5
June 30, 2006 265.0 39.6 30.0 14.5 15.5
September 30,2007 353.4 45.8 33.4 10.4 23.0
September 30,2006 303.4 38.1 28.8 10.7 18.1
December 31, 2007 361.3 48.4 33.8 14.9 18.7
December 31, 2006 288.3 53.1 44.8 17.3 27.5

JCP&L
March 31, 2007 $ 683.7 $ 89.9 $ 71.0 $ 32.7 $ 38.3
March 31, 2006 575.8 73.5 57.3 23.6 33.7
June 30, 2007 780.0 110.2 89.5 39.7 49.8
June 30, 2006 611.5 95.7 78.9 38.6 40.3
September 30,2007 1033.2 143.3 122.1 46.3 75.8
September 30,2006 911.1 156.0 137.7 58.3 79.4
December 31, 2007 746.9 76.4 52.6 30.4 22.2
December 31, 2006 569.3 78.4 63.4 26.2 37.2

* Met-Ed recognized a $355 million non-cash goodwill impairment charge in the fourth quarter of 2006.

ITEM ~~9A(T).~~9A. CONTROLS AND PROCEDURES -- ~~OE, CEI, TE and Penelec (Restated)~~FIRSTENERGY

Evaluation of Disclosure Controls and Procedures

InFirstEnergy's Chief Executive Officer and Chief Financial Officer have reviewed and evaluated such registrant’s disclosure controls and procedures, as defined in the ~~original Form 10-K for the year ended December 31, 2007, each registrant’s chief executive officer~~Securities Exchange Act of 1934 Rules 13a-15(e) and ~~chief financial officer concluded that,~~15d-15(e), as of the end date covered by this report. Based upon this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that FirstEnergy's disclosure controls and procedures were effective as of December 31, 2008.

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the ~~period~~Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework, management conducted an evaluation of the effectiveness of FirstEnergy's internal control over financial reporting under the supervision of FirstEnergy's Chief Executive Officer and Chief Financial Officer. Based on that evaluation, management concluded that FirstEnergy's internal control over financial reporting was effective as of December 31, 2008. The effectiveness of FirstEnergy's internal control over financial reporting, as of December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included in FirstEnergy's 2008 Annual Report to Stockholders and incorporated by reference hereto.

Changes in Internal Control over Financial Reporting

There were no changes in FirstEnergy's internal control over financial reporting during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, FirstEnergy's internal control over financial reporting.

ITEM 9A(T). CONTROLS AND PROCEDURES -- FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec

Evaluation of Disclosure Controls and Procedures

Each registrant's Chief Executive Officer and Chief Financial Officer have reviewed and evaluated such registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 rules 13a-15(e) and 15d-15(e), as of the end date covered by this report. Based upon this evaluation, the respective Chief Executive Officer and Chief Financial Officer concluded that ~~report, the applicable~~such registrant's disclosure controls and procedures were effective as of December 31, 2007. Subsequent to the restatement of the respective registrants’ Consolidated Statements of Cash Flows discussed in the revised Note 1 to the Combined Notes to Consolidated Financial Statements included in the Form 10-K/A, each registrant's chief executive officer and chief financial officer performed an updated review and evaluated such registrant's disclosure controls and procedures. Based upon that updated evaluation and as a result of the material weakness in the internal controls over one aspect of the preparation and review of the Consolidated Statement of Cash Flows discussed below, those officers concluded that, as of the end of the period covered by this report, the applicable registrant's disclosure controls and procedures were ineffective as of December 31, 2007. Based on the modification of internal controls over the preparation and review of the Consolidated Statements of Cash Flows during the fourth quarter of 2008, management believes that it has remediated the material weakness discussed below for each of the registrants.2008.

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework, management conducted an evaluation of the effectiveness of each registrant’s internal control over financial reporting under the supervision of such registrant’s ~~chief executive officer~~Chief Executive Officer and ~~chief financial officer. In the original Form 10-K for the year ended December 31,2007, each registrant’s chief executive officer and chief financial officer~~Chief Financial Officer. Based on that evaluation, management concluded that ~~as of the end of the period covered by that report, the applicable registrant's~~each registrant’s internal control over financial reporting was effective as of December 31, 2007. Subsequent to the restatement discussed in the revised Note 1 to the Combined Notes to Consolidated Financial Statements included in the Form 10-K/A, each registrant's chief executive officer and chief financial officer performed an updated review and evaluated such registrant's internal control over financial reporting. Based upon that updated evaluation and as a result of the material weakness in the internal controls discussed below, those officers concluded that, as of the end of the period covered by this report, the applicable registrant's internal control over financial reporting was ineffective as of December 31, 2007.2008. The effectiveness of each registrant's internal control over financial reporting, as of December 31, ~~2007,~~2008, has not been audited by such registrant’s independent registered public accounting firm.

Changes in Internal Control over Financial Reporting

Related to the remediation of the material weakness described below, there were changes in internal control over financial reporting during the fourth quarter of 2008 for OE, CEI, TE and Penelec. During the fourth quarter of 2008, management of OE, CEI, TE and Penelec identified a material weakness in their accounting for unpaid dividends to FirstEnergy. This material weakness was attributable to an inadequate control to ensure that declared but unpaid dividends to FirstEnergy were not reported as cash used for financing activities on the Consolidated Statement of Cash Flows for each of the affected registrants. As ~~reported in~~a result of this ~~Form 10-K/A, each registrant has amended its original Form 10-K for the year ended December 31, 2007 to restate its~~material weakness, OE, CEI, TE and Penelec restated their Consolidated Statements of Cash Flows for the year ended December 31, 2007, ~~to correct common stock dividend payments reported in cash flows from financing activities.~~the three months ended March 31, 2008, the six months ended June 30, 2008 and the nine months ended September 30, 2008. The Consolidated Statements of ~~Cash Flows for each registrant, as originally filed, erroneously reflected~~Income and Consolidated Balance Sheets were not affected by the ~~dividends declared in~~error. In an effort to remediate the third quarter of 2007 applicable to future quarters' payments as dividends paid in the quarter that they were declared. The corrections resulted in a corresponding change in operating liabilities - accounts payable, included in cash flows from operating activities.

Aidentified material weakness, ~~is a deficiency, or a combination~~management of deficiencies in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis.

~~The restatement described above resulted from a material weakness in the internal controls over one aspect of the preparation~~OE, CEI, TE and review of the Consolidated Statements of Cash Flows. Specifically, the registrants did not have a control that was designed to ensure that declared but unpaid dividends to the registrants’ parent were not reported as cash used for financing activities. This control deficiency resulted in a material misstatement of the registrants’ interim and annual consolidated financial statements. Accordingly, management determined that this control deficiency constitutes a material weakness. The registrants modified their internal controls over the preparation and review of their Consolidated Statements of Cash Flows during the fourth quarter of 2008. ManagementPenelec has implemented a process to segregate dividend declarations with payments applicable to future reporting periods in a unique general ledger account in order to distinguish associated company dividends payable from other associated company accounts payable. Management believes that this process is fully functional, enhances the existing ~~internal controls over financial reporting and remediated the material weakness discussed above for each of the registrants.~~

~~Changes in Internal Control over Financial Reporting~~

~~During the quarter ended December 31, 2007, there were no changes in the registrants'~~ internal control over financial reporting and, prior to the end of the period covered by this report, remediated the material weakness in the internal controls related to the preparation and review of the Consolidated Statements of Cash Flows, which was identified in the fourth quarter of 2008.

There were no changes in internal control over financial reporting during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, ~~the registrants'~~ internal control over financial ~~reporting.~~

reporting for FES, JCP&L and Met-Ed.

ITEM 9B. OTHER INFORMATION

None.

8740

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by Item 10, with respect to identification of FirstEnergy’s directors and with respect to reports required to be filed under Section 16 of the Securities Exchange Act of 1934, is incorporated herein by reference to FirstEnergy’s 2009 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934 and, with respect to identification of executive officers, to “Part I, Item 1. Business – Executive Officers” herein.

The Board of Directors, upon recommendation of the Corporate Governance and Audit Committees, has determined that Ernest J. Novak, Jr., an independent director, is the audit committee financial expert.

FirstEnergy makes available on its Web site at http://www.firstenergycorp.com/ir its Corporate Governance Policies and the charters for each of the following committees of the Board of Directors: Audit; Corporate Governance; Compensation; Finance; and Nuclear. The Corporate Governance Policies and Board committee charters are also available in print upon written request to Rhonda S. Ferguson, Corporate Secretary, FirstEnergy Corp., 76 South Main Street, Akron, OH 44308-1890.

FirstEnergy has adopted a Code of Business Conduct, which applies to all employees, including the Chief Executive Officer, the Chief Financial Officer and the Chief Accounting Officer. In addition, the Board of Directors has its own Code of Business Conduct. These Codes can be found on the Web site provided in the previous paragraph or upon written request to the Corporate Secretary.

Pursuant to Section 303A.12(a) of the New York Stock Exchange Listed Company Manual, the Company submitted the Annual CEO Certification to the NYSE on May 23, 2008.

ITEM 11.

EXECUTIVE COMPENSATION

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by Items 11, 12 and 13 is incorporated herein by reference to FirstEnergy’s 2009 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

A summary of the audit and audit-related fees rendered by PricewaterhouseCoopers LLP for the years ended December 31, 2008 and 2007 are as follows:

	Audit Fees(1)				Audit-Related Fees
Company	2008		2007		2008		2007
	(In thousands)
FES	$	835	$	1,091	$	-	$	494
OE		1,155		1,014		-		-
CEI		764		719		-		-
TE		598		540		-		-
JCP&L		682		701		-		-
Met-Ed		583		528		-		-
Penelec		595		586		-		-
Other subsidiaries		607		886		-		-
Total FirstEnergy	$	5,819	$	6,065	$	-	$	494

(1)

Professional services rendered for the audits of FirstEnergy’s annual financial statements and reviews of financial statements included in FirstEnergy’s Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.

Tax and Other Fees

There were no other fees billed to FirstEnergy for tax or other services for the years ended December 31, 2008 and 2007.

Additional information required by this item is incorporated herein by reference to FirstEnergy's 2009 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.

PART IV

ITEM 15. ~~EXHIBITS.~~EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

1. Financial Statements

Included in Part II of this report and incorporated herein by reference to the 2008 Annual Report of FirstEnergy (Exhibit 13.1) and the combined 2008 Annual Report of FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec (Exhibit 13.2) at the pages indicated.

	FirstEnergy	FES	OE	CEI	TE	JCP&L	Met-Ed	Penelec

Management Reports	59	6	16	26	36	47	58	69
Report of Independent Registered Public Accounting Firm	60	7	17	27	37	48	59	70
Statements of Income, Three Years Ended December 31, 2008	61	8	18	28	38	49	60	71
Balance Sheets, December 31, 2008 and 2007	62	9	19	29	39	50	61	72
Statements of Capitalization, December 31, 2008 and 2007	N/A	10	20	30	40	51	62	73
Statements of Common Stockholders’ Equity, Three Years Ended December 31, 2008	63	11	21	31	41	52	63	74
Statements of Cash Flows, Three Years Ended December 31, 2008	64	12	22	32	42	53	64	75
Notes to Financial Statements	65-108	91-145	91-145	91-145	91-145	91-145	91-145	91-145

~~Exhibit~~2.

Financial Statement Schedules

Included in Part IV of this report:

	FirstEnergy	FES	OE	CEI	TE	JCP&L	Met-Ed	Penelec

Report of Independent Registered Public Accounting Firm	73	74	75	76	77	78	79	80

Schedule II -- Consolidated Valuation and Qualifying Accounts, Three Years Ended December 31, 2008	81	82	83	84	85	86	87	88

Schedules other than the schedule listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto.

~~Number~~

3.	Exhibits – FirstEnergy

Exhibit

Number

3-1	Amended Articles of Incorporation of FirstEnergy Corp. (Form S-3 filed February 3, 1997, Exhibit 4(a), File No. 333-21011)

(A) 3-2	FirstEnergy Corp. Amended Code of Regulations.
OE
4-1	23Indenture, dated November 15, 2001, between FirstEnergy Corp. and The Bank of New York Mellon, as Trustee. (Form S-3 filed September 21, 2001, Exhibit 4(a), File No. 333-69856)

(A)(B) 10-1	FirstEnergy Corp. 2007 Incentive Plan, effective May 15, 2007.

(A)(B) 10-2	Amended FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, amended and restated as of January 1, 2005 and ratified as of September 18, 2007.

(B) 10-3	FirstEnergy Corp. Supplemental Executive Retirement Plan, amended January 1, 1999. (1999 Form 10-K, Exhibit 10-4)

(B) 10-4	Stock Option Agreement between FirstEnergy Corp. and officers dated November 22, 2000. (2000 Form 10-K, Exhibit 10-3)

(B) 10-5	Stock Option Agreement between FirstEnergy Corp. and officers dated March 1, 2000. (2000 Form 10-K, Exhibit 10-4)

(B) 10-6	Stock Option Agreement between FirstEnergy Corp. and director dated January 1, 2000. (2000 Form 10-K, Exhibit 10-5)

(B) 10-7	Stock Option Agreement between FirstEnergy Corp. and two directors dated January 1, 2001. (2000 Form 10-K, Exhibit 10-6)

(B) 10-8	Stock Option Agreements between FirstEnergy Corp. and One Director dated January 1, 2002. (2001 Form 10-K, Exhibit 10-5)

(B) 10-9	FirstEnergy Corp. Executive Deferred Compensation Plan, amended and restated as of January 1, 2005 and ratified as of September 18, 2007. (September 2007 10-Q, Exhibit 10.2)

(B) 10-10	Executive Incentive Compensation Plan-Tier 2. (2001 Form 10-K, Exhibit 10-7)

(B) 10-11	Executive Incentive Compensation Plan-Tier 3. (2001 Form 10-K, Exhibit 10-8)

(B) 10-12	Executive Incentive Compensation Plan-Tier 4. (2001 Form 10-K, Exhibit 10-9)

(B) 10-13	Executive Incentive Compensation Plan-Tier 5. (2001 Form 10-K, Exhibit 10-10)

(B) 10-14	Amendment to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, effective April 5, 2001. (2001 Form 10-K, Exhibit 10-11)

(B) 10-15	Form of Amendment, effective November 7, 2001, to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, Deferred Remuneration Plan for Outside Directors of GPU, Inc., and Retirement Plan for Outside Directors of GPU, Inc. (2001 Form 10-K, Exhibit 10-12)

(B) 10-16	GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group, Inc. Employees. (2001 Form 10-K, Exhibit 10-13)

(B) 10-17	Executive and Director Stock Option Agreement dated June 11, 2002. (2002 Form 10-K, Exhibit 10-1)

(B) 10-18	Director Stock Option Agreement. (2002 Form 10-K, Exhibit 10-2)

(B) 10-19	Executive Incentive Compensation Plan 2002. (2002 Form 10-K, Exhibit 10-28)

(B) 10-20	GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries as amended and restated to reflect amendments through June 3, 1999. (1999 Form 10-K, Exhibit 10-V, File No. 1-6047, GPU, Inc.)

(B) 10-21	Form of 1998 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (1997 Form 10-K, Exhibit 10-Q, File No. 1-6047, GPU, Inc.)

(B) 10-22	Form of 1999 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (1999 Form 10-K, Exhibit 10-W, File No. 1-6047, GPU, Inc.)

(B) 10-23	Form of 2000 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (1999 Form 10-K, Exhibit 10-W, File No. 1-6047, GPU, Inc.)

(B) 10-24	Deferred Remuneration Plan for Outside Directors of GPU, Inc. as amended and restated effective August 8, 2000. (1999 Form 10-K, Exhibit 10-O, File No. 1-6047, GPU, Inc.)

(B) 10-25	Retirement Plan for Outside Directors of GPU, Inc. as amended and restated as of August 8, 2000. (1999 Form 10-K, Exhibit 10-N, File No. 1-6047, GPU, Inc.)

(B) 10-26	Forms of Estate Enhancement Program Agreements entered into by certain former GPU directors. (1999 Form 10-K, Exhibit 10-JJ, File No. 1-6047, GPU, Inc.)

(B) 10-27	Employment Agreement for Richard R. Grigg dated February 26, 2008. (2007 Form 10-K, Exhibit 10.5)

(B) 10-28	Stock Option Agreement between FirstEnergy Corp. and an officer dated August 20, 2004. (September 2004 Form 10-Q, Exhibit 10-42)

(B) 10-29	Executive Bonus Plan between FirstEnergy Corp. and Officers effective November 3, 2004. (September 2004 Form 10-Q, Exhibit 10-44)

10-30	Consent Decree dated March 18, 2005. (Form 8-K dated March 18, 2005 by FirstEnergy Corp., Exhibit 10-1)

(C) 10-31	Form of Guaranty Agreement dated as of December 16, 2005 between FirstEnergy Corp. and FirstEnergy Solutions Corp. in Favor of Barclays Bank PLC as Administrative Agent for the Banks. (2005 Form 10-K, Exhibit 10-1)

(D) 10-32	Form of Guaranty Agreement dated as of April 3, 2006 by FirstEnergy Corp. in favor of the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent, under the related Letter of Credit and Reimbursement Agreement. (March 2006 Form 10-Q, Exhibit 10-1)

(B) 10-33	Form of Restricted Stock Agreement between FirstEnergy Corp. and A. J. Alexander, dated February 27, 2006. (March 2006 Form 10-Q, Exhibit 10-6)

(B) 10-34	Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy Corp. and A.J. Alexander, dated March 1, 2006. (March 2006 Form 10-Q, Exhibit 10-7)

(B) 10-35	Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy Corp. and named executive officers, dated March 1, 2006. (March 2006 Form 10-Q, Exhibit 10-8)

(B) 10-36	Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy Corp. and R.H. Marsh, dated March 1, 2006. (March 2006 Form 10-Q, Exhibit 10-9)

10-37	Confirmation dated March 1, 2007 between FirstEnergy Corp. and Morgan Stanley and Co., International Limited. (March 2007 Form 10-Q, Exhibit 10.1)

10-38	Form of U.S. $250,000,000 Credit Agreement, dated as of March 2, 2007, between FirstEnergy Corp., as Borrower, and Morgan Stanley Senior Funding, Inc., as Lender. (March 2007 Form 10-Q, Exhibit 10.2)

10-39	Form of Guaranty dated as of March 2, 2007, between FirstEnergy Corp., as Guarantor, and Morgan Stanley Senior Funding, Inc., as Lender under a U.S. $250,000,000 Credit Agreement dated as of March 2, 2007, with FirstEnergy Solutions Corp., as Borrower. (March 2007 Form 10-Q, Exhibit 10.2)

(B) 10-40	FirstEnergy Corp. Supplemental Executive Retirement Plan as amended September 18, 2007. (September 2007 Form 10-Q, Exhibit 10.2)

(B) 10-41	Employment Agreement between FirstEnergy Corp. and Gary R. Leidich, dated February 26, 2008. (2007 Form 10-K, Exhibit 10-88)

(B) 10-42	Form of Restricted Stock Unit Agreement for Gary R. Leidich (per Employment Agreement dated February 26, 2008). (2007 Form 10-K, Exhibit 10-90)

(B) 10-43	Form of Restricted Stock Agreement Amendment for Gary R. Leidich dated February 26, 2008. (2007 Form 10-K, Exhibit 10-91)

(B) 10-44	Form of Restricted Stock Unit Agreement for Richard R. Grigg (per Employment Agreement dated February 26, 2008). (2007 Form 10-K, Exhibit 10-92)

(B) 10-45	Form of Restricted Stock Unit Agreement for named executive officers dated March 3, 2008. (2007 Form 10-K, Exhibit 10-93)

(B) 10-46	Form of 2007 Incentive Compensation Plan Performance Share Award for the performance period January 1, 2008 to December 31, 2010. (2007 Form 10-K, Exhibit 10-94)


10-47	U.S. $300,000,000 Credit Agreement, dated as of October 8, 2008, among FirstEnergy Generation Corp., as Borrower, FirstEnergy Corp. and FirstEnergy Solutions Corp., as Guarantors, Credit Suisse and the other Banks parties thereto from time to time, as Banks and Credit Suisse, as Administrative Agent. (September 2008 Form 10-Q, Exhibit 10.1)

(A)(B) 10-48	Form of 2009-2011 Performance Share Award Agreement effective January 1, 2009

(A)(B) 10-49	Form of Performance-Adjusted Restricted Stock Unit Award Agreement as of March 2, 2009

(A) 12-1	Consolidated ratios of earnings to fixed charges.

(A) 13-1	FirstEnergy 2008 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10–K are to be deemed “filed” with the SEC.)

(A) 21	List of Subsidiaries of the Registrant at December 31, 2008.

(A) 23-1	Consent of Independent Registered Public Accounting Firm.
	~~31.1~~
(A) 31-1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	~~31.2~~
(A) 31-2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).

(A) 32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.
~~CEI~~
(A)	23	~~Consent of Independent Registered Public Accounting Firm.~~Provided herein in electronic format as an exhibit.
	~~31.1~~
(B)	Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.

(C)	Four substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to four other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority, the Ohio Air Quality Authority and Beaver County Industrial Development Authority, Pennsylvania, relating to pollution control notes of FirstEnergy Nuclear Generation Corp.

(D)	Three substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to three other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority and the Beaver County Industrial Development Authority relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp.

3. Exhibits – FES

3-1	Articles of Incorporation of FirstEnergy Solutions Corp., as amended August 31, 2001. (Form S-4 filed August 6, 2007, Exhibit 3.1)

3-2	Code of Regulations of FirstEnergy Solutions Corp. (Form S-4 filed August 6, 2007, Exhibit 3.4)

10-1	Form of 6.85% Exchange Certificate due 2034. (Form S-4 filed August 6, 2007, Exhibit 4.1)

10-2	Guaranty of FirstEnergy Solutions Corp., dated as of July 1, 2007. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-9)

10-3	Indenture of Trust, Open-End Mortgage and Security Agreement, dated as of July 1, 2007, between the applicable Lessor and The Bank of New York Trust Company, N.A., as Indenture Trustee. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-3)

10-4	6.85% Lessor Note due 2034. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-3)

10-5	Registration Rights Agreement, dated as of July 13, 2007, among FirstEnergy Generation Corp., FirstEnergy Solutions Corp., The Bank of New York Trust Company, N.A., as Pass Through Trustee, Morgan Stanley & Co. Incorporated, and Credit Suisse Securities (USA) LLC, as representatives of the several initial purchasers named in the Purchase Agreement. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-14)

10-6	Participation Agreement, dated as of June 26, 2007, among FirstEnergy Generation Corp., as Lessee, FirstEnergy Solutions Corp., as Guarantor, the applicable Lessor, U.S. Bank Trust National Association, as Trust Company, the applicable Owner Participant, The Bank of New York Trust Company, N.A., as Indenture Trustee, and The Bank of New York Trust Company, N.A., as Pass Through Trustee. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-1)

10-7	Trust Agreement, dated as of June 26, 2007, between the applicable Owner Participant and U.S. Bank Trust National Association, as Owner Trustee. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-2)

10-8	Pass Through Trust Agreement, dated as of June 26, 2007, among FirstEnergy Generation Corp., FirstEnergy Solutions Corp., and The Bank of New York Trust Company, N.A., as Pass Through Trustee. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-12)

10-9	Bill of Sale and Transfer, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-5)

10-10	Facility Lease Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-6)

10-11	Site Lease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-7)

10-12	Site Sublease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-8)

10-13	Support Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-10)

10-14	Second Amendment to the Bruce Mansfield Units 1, 2, and 3 Operating Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp. (333-21011), Exhibit 10-11)

10-15	OE Fossil Purchase and Sale Agreement by and between Ohio Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (June 2005 Form 10-Q filed by FirstEnergy Corp. (333-21011), Exhibit 10.2)

10-16	CEI Fossil Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (June 2005 Form 10-Q, Exhibit 10.6)

10-17	TE Fossil Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (June 2005 Form 10-Q, Exhibit 10.2)

10-18	Agreement, dated August 26, 2005, by and between FirstEnergy Generation Corp. and Bechtel Power Corporation. (September 2005 Form 10-Q, Exhibit 10-2)

10-19	CEI Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.15)


10-20	CEI Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Cleveland Electric Illuminating Company. (Form S-4/A filed August 20, 2007, Exhibit 10.16)

10-21	OE Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.17)

10-22	OE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and Ohio Edison Company. (Form S-4/A filed August 20, 2007, Exhibit 10.18)

10-23	Amendment No. 1 to OE Fossil Security Agreement, dated as of June 30, 2007, between FirstEnergy Generation Corp. and Ohio Edison Company. (Form S-4/A filed August 20, 2007, Exhibit 10.19)

10-24	PP Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.20)

10-25	PP Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and Pennsylvania Power Company. (Form S-4/A filed August 20, 2007, Exhibit 10.21)

10-26	Amendment No. 1 to PP Fossil Security Agreement, dated as of June 30, 2007, between FirstEnergy Generation Corp. and Pennsylvania Power Company. (Form S-4/A filed August 20, 2007, Exhibit 10.22)

10-27	TE Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.23)

10-28	TE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Toledo Edison Company. (Form S-4/A filed August 20, 2007, Exhibit 10.24)

10-29	CEI Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.25)

10-30	CEI Nuclear Security Agreement, dated December 16, 2005, by and between FirstEnergy Nuclear Generation Corp. and The Cleveland Electric Illuminating Company. (Form S-4/A filed August 20, 2007, Exhibit 10.26)

10-31	OE Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.27)

10-32	PP Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.28)

10-33	TE Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.29)

10-34	TE Nuclear Security Agreement, dated December 16, 2005, by and between FirstEnergy Nuclear Generation Corp. and The Toledo Edison Company. (Form S-4/A filed August 20, 2007, Exhibit 10.30)

10-35	Mansfield Power Supply Agreement, dated August 10, 2006, among The Cleveland Electric Illuminating Company, The Toledo Edison Company and FirstEnergy Generation Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.31)

10-36	Nuclear Power Supply Agreement, dated August 10, 2006, between FirstEnergy Nuclear Generation Corp. and FirstEnergy Solutions Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.32)

10-37	Revised Power Supply Agreement, dated December 8, 2006, among FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. (Form S-4/A filed August 20, 2007, Exhibit 10.34)


10-38	GENCO Power Supply Agreement, dated January 1, 2007, between FirstEnergy Generation Corp. and FirstEnergy Solutions Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.36)

10-39	Form of U.S. $250,000,000 Credit Agreement, dated as of March 2, 2007, between FirstEnergy Solutions Corp., as Borrower, and Morgan Stanley Senior Funding, Inc., as Lender. (March 2007 Form 10-Q filed by FirstEnergy Corp., Exhibit 10-2)

10-40	Form of Guaranty dated as of March 2, 2007, between FirstEnergy Corp., as Guarantor, and Morgan Stanley Senior Funding, Inc., as Lender under the U.S. $250,000,000 Credit Agreement, dated as of March 2, 2007, with FirstEnergy Solutions Corp., as Borrower. (March 2007 Form 10-Q filed by FirstEnergy Corp., Exhibit 10-23)

10-41	Guaranty, dated as of March 26, 2007, by FirstEnergy Generation Corp. on behalf of FirstEnergy Solutions Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.39)

10-42	Guaranty, dated as of March 26, 2007, by FirstEnergy Solutions Corp. on behalf of FirstEnergy Generation Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.40)

10-43	Guaranty, dated as of March 26, 2007, by FirstEnergy Solutions Corp. on behalf of FirstEnergy Nuclear Generation Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.41)

10-44	Guaranty, dated as of March 26, 2007, by FirstEnergy Nuclear Generation Corp. on behalf of FirstEnergy Solutions Corp. (Form S-4/A filed August 20, 2007, Exhibit 10.42)

(B) 10-45	Form of Guaranty Agreement dated as of December 16, 2005 between FirstEnergy Corp. and FirstEnergy Solutions Corp. in Favor of Barclays Bank PLC as Administrative Agent for the Banks. (2005 Form 10-K, Exhibit 10-58)

(B) 10-46	Form of Trust Indenture dated as of December 1, 2005 between Ohio Water Development Authority and JP Morgan Trust Company related to issuance of FirstEnergy Nuclear Generation Corp. pollution control revenue refunding bonds. (2005 Form 10-K, Exhibit 10-59)

10-47	GENCO Power Supply Agreement dated as of October 14, 2005 between FirstEnergy Generation Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer). (2005 Form 10-K, Exhibit 10-60)

10-48	Nuclear Power Supply Agreement dated as of October 14, 2005 between FirstEnergy Nuclear Generation Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer). (2005 Form 10-K, Exhibit 10-61)

(B) 10-49	Form of Letter of Credit and Reimbursement Agreement Dated as of December 16, 2005 among FirstEnergy Nuclear Generation Corp., and the Participating Banks and Barclays Bank PLC. (2005 Form 10-K, Exhibit 10-62)

(B) 10-50	Form of Waste Water Facilities and Solid Waste Facilities Loan Agreement between Ohio Water Development Authority and FirstEnergy Nuclear Generation Corp., dated as of December 1, 2005. (2005 Form 10-K, Exhibit 10-63)

10-51	Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and the Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer). (2005 Form 10-K, Exhibit 10-64)

10-52	Mansfield Power Supply Agreement dated as of October 14, 2005 between Cleveland Electric Illuminating Company and The Toledo Edison Company (Sellers) and FirstEnergy Generation Corp. (Buyer). (2005 Form 10-K, Exhibit 10-65)

10-53	Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and the FirstEnergy Operating Companies – Ohio Edison Company, The Cleveland Electric Illuminating Company, and The Toledo Edison Company (Buyers). (2005 Form 10-K, Exhibit 10-66)

10-54	Electric Power Supply Agreement dated as of October 3, 2005 between FirstEnergy Solutions Corp. (Seller) and Pennsylvania Power Company (Buyer). (2005 Form 10-K, Exhibit 10-67)

(C) 10-55	Form of Letter of Credit and Reimbursement Agreement dated as of April 3, 2006 among FirstEnergy Generation Corp., the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent. (March 2006 Form 10-Q, Exhibit 10-2)

(C) 10-56	Form of Trust Indenture dated as of April 1, 2006 between the Ohio Water Development Authority and The Bank of New York Trust Company, N.A. as Trustee securing pollution control revenue refunding bonds issued on behalf of FirstEnergy Generation Corp. (March 2006 Form 10-Q, Exhibit 10-3)

(C) 10-57	Form of Waste Water Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Generation Corp. dated as of April 1, 2006. (March 2006 Form 10-Q, Exhibit 10-4)

(D) 10-58	Form of Trust Indenture dated as of December 1, 2006 between the Ohio Water Development Authority and The Bank of New York Trust Company, N.A. as Trustee securing State of Ohio Pollution Control Revenue Refunding Bonds (FirstEnergy Nuclear Generation Corp. Project). (2006 Form 10-K, Exhibit 10-77)

(D) 10-59	Form of Waste Water Facilities and Solid Waste Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Nuclear Generation Corp. dated as of December 1, 2006. (2006 Form 10-K, Exhibit 10-80)

10-60	Consent Decree dated March 18, 2005. (Form 8-K filed March 18, 2005 by FirstEnergy Corp., Exhibit 10.1)

10-61	Amendment to Agreement for Engineering, Procurement and Construction of Air Quality Control Systems by and between FirstEnergy Generation Corp. and Bechtel Power Corporation dated September 14, 2007. (September 2007 Form 10-Q, Exhibit 10.1)

10-62	Asset Purchase Agreement by and between Calpine Corporation, as Seller, and FirstEnergy Generation Corp., as Buyer, dated as of January 28, 2008. (2007 Form 10-K, Exhibit 10-48)

10-63	U.S. $300,000,000 Credit Agreement, dated as of October 8, 2008, among FirstEnergy Generation Corp., as Borrower, FirstEnergy Corp. and FirstEnergy Solutions Corp., as Guarantors, Credit Suisse and the other Banks parties thereto from time to time, as Banks and Credit Suisse, as Administrative Agent. (September 2008 Form 10-Q, Exhibit 10.1)

(A) 12-2	Consolidated ratios of earnings to fixed charges.

(A) 13-2	FES 2008 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed “filed” with the SEC.)

(A) 31-1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	~~31.2~~
(A) 31-2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).

(A) 32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.

(A)	Provided herein in electronic format as an exhibit.

(B)	Four substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to four other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority, the Ohio Air Quality Authority and Beaver County Industrial Development Authority, Pennsylvania, relating to pollution control notes of FirstEnergy Nuclear Generation Corp.

(C)	Three substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to three other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority and the Beaver County Industrial Development Authority relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp.

(D)	Seven substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to one other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority, three other series of pollution control bonds issued by the Ohio Air Quality Development Authority and the three other series of pollution control bonds issued by the Beaver County Industrial Development Authority, relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp.

3. Exhibits – OE

2-1		Agreement and Plan of Merger, dated as of September 13, 1996, between Ohio Edison Company and Centerior Energy Corporation. (Form 8–K filed September 17, 1996, Exhibit 2–1)

3-1		Amended and Restated Articles of Incorporation of Ohio Edison Company, Effective December 18, 2007. (2007 Form 10-K, Exhibit 3-4)

3-2		Amended and Restated Code of Regulations of Ohio Edison Company, dated December 14, 2007. (2007 Form 10-K, Exhibit 3-5)

4-1	General Mortgage Indenture and Deed of Trust dated as of January 1, 1998 between Ohio Edison Company and the Bank of New York, as Trustee, as amended and supplemented by Supplemental Indentures: (Registration No. 333-05277, Exhibit 4(g))
	23
4-1(a)	February 1, 2003 (2003 Form10-K, File No. 1-2578, Exhibit 4-4)
4-1(b)	March 1, 2003 (2003 Form 10-K, File No. 1-2578, Exhibit 4-5)
4-1(c)	August 1, 2003 (2003 Form 10-K, File No. 1-2578, Exhibit 4-6)
4-1(d)	June 1, 2004 (2004 Form 10-K, File No. 1-2578, Exhibit 4-4)
4-1(e)	December 1, 2004 (2004 Form 10-K, File No. 1-2578, Exhibit 4-4)
4-1(f)	April 1, 2005 (June 2005 Form 10-Q, File No. 1-2578, Exhibit 4-4)
4-1(g)	April 15, 2005 (June 2005 Form 10-Q, File No. 1-2578, Exhibit 4-5)
4-1(h)	June 1, 2005 (June 2005 Form 10-Q, File No. 1-2578, Exhibit 4-6)
4-1(i)	October 1, 2008 (Form 8-K filed October 22, 2008, Exhibit 4.1)

4-2	Indenture dated as of April 1, 2003 between Ohio Edison Company and The Bank of New York, as Trustee. (2003 Form 10-K, Exhibit 4-3)

4-2(a)	Officer’s Certificate (including the forms of the 6.40% Senior Notes due 2016 and the 6.875% Senior Notes due 2036), dated June 21, 2006. (Form 8-K filed June 27, 2006, Exhibit 4)

10-1	Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(2))

10-2	Amendment No. 1 dated January 4, 1974 to Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-68906, Exhibit 5(c)(3))

10-3	Amendment No. 4 dated as of July 1, 1985 to the Bond Guaranty dated as of October 1, 1973, as amended, by the CAPCO Companies to National City Bank as Bond Trustee. (1985 Form 10-K, Exhibit 10-30)

10-4	Amendment No. 5 dated as of May 1, 1986, to the Bond Guaranty by the CAPCO Companies to National City Bank as Bond Trustee. (1986 Form 10-K, Exhibit 10-33)

10-5	Amendment No. 6A dated as of December 1, 1991, to the Bond Guaranty dated as of October 1, 1973, by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (1991 Form 10-K, Exhibit 10-33)


10-6	Amendment No. 6B dated as of December 30, 1991, to the Bond Guaranty dated as of October 1, 1973 by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (1991 Form 10-K, Exhibit 10-34)

(B) 10-7	Ohio Edison System Executive Supplemental Life Insurance Plan. (1995 Form 10-K, Exhibit 10-44)

(B) 10-8	Ohio Edison System Executive Incentive Compensation Plan. (1995 Form 10-K, Exhibit 10-45)

(B) 10-9	Ohio Edison System Restated and Amended Supplemental Executive Retirement Plan. (1995 Form 10-K, Exhibit 10-47)

(B) 10-10	Form of Amendment, effective November 7, 2001, to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, Deferred Remuneration Plan for Outside Directors of GPU, Inc., and Retirement Plan for Outside Directors of GPU, Inc. (2001 Form 10-K, Exhibit 10-26)

(B) 10-11	GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group, Inc. Employees. (2001 Form 10-K, Exhibit 10-27)

(B) 10-12	Severance pay agreement between Ohio Edison Company and A. J. Alexander. (1995 Form 10-K, Exhibit 10-50)

(C) 10-13	Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Hereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-1)

(C) 10-14	Amendment No. 1 dated as of September 1, 1987 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company (now The Bank of New York), as Indenture Trustee, and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-46)

(C) 10-15	Amendment No. 3 dated as of May 16, 1988 to Participation Agreement dated as of March 16, 1987, as amended among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-47)

(C) 10-16	Amendment No. 4 dated as of November 1, 1991 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-47)

(C) 10-17	Amendment No. 5 dated as of November 24, 1992 to Participation Agreement dated as of March 16, 1987, as amended, among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company as Lessee. (1992 Form 10-K, Exhibit 10-49)

(C) 10-18	Amendment No. 6 dated as of January 12, 1993 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-50)

(C) 10-19	Amendment No. 7 dated as of October 12, 1994 to Participation Agreement dated as of March 16, 1987 as amended, among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-54)

(C) 10-20	Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (1986 Form 10-K, Exhibit 28-2)

(C) 10-21	Amendment No. 1 dated as of September 1, 1987 to Facility Lease dated as of March 16, 1997 between The First National Bank of Boston, as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-49)

(C) 10-22	Amendment No. 2 dated as of November 1, 1991, to Facility Lease dated as of March 16, 1987, between The First National Bank of Boston, as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-50)

(C) 10-23	Amendment No. 3 dated as of November 24, 1992 to Facility Lease dated as March 16, 1987 as amended, between The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited partnership, as Owner Participant and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-54)

(C) 10-24	Amendment No. 4 dated as of January 12, 1993 to Facility Lease dated as of March 16, 1987 as amended, between, The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-59)

(C) 10-25	Amendment No. 5 dated as of October 12, 1994 to Facility Lease dated as of March 16, 1987 as amended, between, The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-60)

(C) 10-26	Letter Agreement dated as of March 19, 1987 between Ohio Edison Company, Lessee, and The First National Bank of Boston, Owner Trustee under a Trust dated March 16, 1987 with Chase Manhattan Realty Leasing Corporation, required by Section 3(d) of the Facility Lease. (1986 Form 10-K, Exhibit 28-3)

(C) 10-27	Ground Lease dated as of March 16, 1987 between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with the Owner Participant, Tenant. (1986 Form 10-K, Exhibit 28-4)

(C) 10-28	Trust Agreement dated as of March 16, 1987 between Perry One Alpha Limited Partnership, as Owner Participant, and The First National Bank of Boston. (1986 Form 10-K, Exhibit 28-5)

(C) 10-29	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of March 16, 1987 with Perry One Alpha Limited Partnership, and Irving Trust Company, as Indenture Trustee. (1986 Form 10-K, Exhibit 28-6)

(C) 10-30	Supplemental Indenture No. 1 dated as of September 1, 1987 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee and Irving Trust Company (now The Bank of New York), as Indenture Trustee. (1991 Form 10-K, Exhibit 10-55)

(C) 10-31	Supplemental Indenture No. 2 dated as of November 1, 1991 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and The Bank of New York, as Indenture Trustee. (1991 Form 10-K, Exhibit 10-56)

(C) 10-32	Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-7)

(C) 10-33	Amendment No. 1 dated as of November 1, 1991 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (1991 Form 10-K, Exhibit 10-58)

(C) 10-34	Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (1994 Form 10-K, Exhibit 10-69)

(C) 10-35	Amendment No. 3 dated as of October 12, 1994 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (1994 Form 10-K, Exhibit 10-70)

(C) 10-36	Partial Mortgage Release dated as of March 19, 1987 under the Indenture between Ohio Edison Company and Bankers Trust Company, as Trustee, dated as of the 1st day of August 1930. (1986 Form 10-K, Exhibit 28-8)

(C) 10-37	Assignment, Assumption and Further Agreement dated as of March 16, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (1986 Form 10-K, Exhibit 28-9)

(C) 10-38	Additional Support Agreement dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, and Ohio Edison Company. (1986 Form 10-K, Exhibit 28-10)

(C) 10-39	Bill of Sale, Instrument of Transfer and Severance Agreement dated as of March 19, 1987 between Ohio Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership. (1986 Form 10-K, Exhibit 28-11)

(C) 10-40	Easement dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, Grantee. (1986 Form 10-K, Exhibit 28-12)

10-41	Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Hereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-13)

10-42	Amendment No. 1 dated as of September 1, 1987 to Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, The Original Loan Participants Listed in Schedule 1 thereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-65)

10-43	Amendment No. 4 dated as of November 1, 1991, to Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-66)

10-44	Amendment No. 5 dated as of November 24, 1992 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-71)

10-45	Amendment No. 6 dated as of January 12, 1993 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-80)

10-46	Amendment No. 7 dated as of October 12, 1994 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-81)

10-47	Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, Lessor, and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-14)

10-48	Amendment No. 1 dated as of September 1, 1987 to Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-68)

10-49	Amendment No. 2 dated as of November 1, 1991 to Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-69)

10-50	Amendment No. 3 dated as of November 24, 1992 to Facility Lease dated as of March 16, 1987, as amended, between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-75)

10-51	Amendment No. 4 dated as of January 12, 1993 to Facility Lease dated as of March 16, 1987 as amended between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-76)

10-52	Amendment No. 5 dated as of October 12, 1994 to Facility Lease dated as of March 16, 1987 as amended between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-87)

10-53	Letter Agreement dated as of March 19, 1987 between Ohio Edison Company, as Lessee, and The First National Bank of Boston, as Owner Trustee under a Trust, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, required by Section 3(d) of the Facility Lease. (1986 Form 10-K, Exhibit 28-15)

10-54	Ground Lease dated as of March 16, 1987 between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, Tenant. (1986 Form 10-K, Exhibit 28-16)

10-55	Trust Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation, as Owner Participant, and The First National Bank of Boston. (1986 Form 10-K, Exhibit 28-17)

10-56	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, and Irving Trust Company, as Indenture Trustee. (1986 Form 10-K, Exhibit 28-18)

10-57	Supplemental Indenture No. 1 dated as of September 1, 1987 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and Irving Trust Company (now The Bank of New York), as Indenture Trustee. (1991 Form 10-K, Exhibit 10-74)

10-58	Supplemental Indenture No. 2 dated as of November 1, 1991 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and The Bank of New York, as Indenture Trustee. (1991 Form 10-K, Exhibit 10-75)

10-59	Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-19)

10-60	Amendment No. 1 dated as of November 1, 1991 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (1991 Form 10-K, Exhibit 10-77)

10-61	Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (1994 Form 10-K, Exhibit 10-96)

10-62	Amendment No. 3 dated as of October 12, 1994 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (1994 Form 10-K, Exhibit 10-97)

10-63	Assignment, Assumption and Further Agreement dated as of March 16, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (1986 Form 10-K, Exhibit 28-20)

10-64	Additional Support Agreement dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, and Ohio Edison Company. (1986 Form 10-K, Exhibit 28-21)

10-65	Bill of Sale, Instrument of Transfer and Severance Agreement dated as of March 19, 1987 between Ohio Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, Buyer. (1986 Form 10-K, Exhibit 28-22)

10-66	Easement dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, Grantee. (1986 Form 10-K, Exhibit 28-23)

10-67	Refinancing Agreement dated as of November 1, 1991 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee, The Bank of New York, as Collateral Trust Trustee, The Bank of New York, as New Collateral Trust Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-82)

10-68	Refinancing Agreement dated as of November 1, 1991 among Security Pacific Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee, The Bank of New York, as Collateral Trust Trustee, The Bank of New York as New Collateral Trust Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-83)

10-69	Ohio Edison Company Master Decommissioning Trust Agreement for Perry Nuclear Power Plant Unit One, Perry Nuclear Power Plant Unit Two, Beaver Valley Power Station Unit One and Beaver Valley Power Station Unit Two dated July 1, 1993. (1993 Form 10-K, Exhibit 10-94)

(D) 10-70	Participation Agreement dated as of September 15, 1987, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company as Lessee. (1987 Form 10-K, Exhibit 28-1)

(D) 10-71	Amendment No. 1 dated as of February 1, 1988, to Participation Agreement dated as of September 15, 1987, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-2)

(D) 10-72	Amendment No. 3 dated as of March 16, 1988 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-99)

(D) 10-73	Amendment No. 4 dated as of November 5, 1992 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-100)

(D) 10-74	Amendment No. 5 dated as of September 30, 1994 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-118)

(D) 10-75	Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-3)

(D) 10-76	Amendment No. 1 dated as of February 1, 1988, to Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-4)

(D) 10-77	Amendment No. 2 dated as of November 5, 1992, to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-103)

(D) 10-78	Amendment No. 3 dated as of September 30, 1994 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-122)

(D) 10-79	Ground Lease and Easement Agreement dated as of September 15, 1987, between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, Tenant. (1987 Form 10-K, Exhibit 28-5)

(D) 10-80	Trust Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Limited Partnership, as Owner Participant, and The First National Bank of Boston. (1987 Form 10-K, Exhibit 28-6)

(D) 10-81	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-7)

(D) 10-82	Supplemental Indenture No. 1 dated as of February 1, 1988 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with Beaver Valley Two Pi Limited Partnership and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-8)

(D) 10-83	Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-9)

(D) 10-84	Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-128)

(D) 10-85	Amendment No. 2 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-129)

(D) 10-86	Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-10)

(D) 10-87	Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-131)

(D) 10-88	Amendment No. 2 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-132)

(D) 10-89	Assignment, Assumption and Further Agreement dated as of September 15, 1987, among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (1987 Form 10-K, Exhibit 28-11)

(D) 10-90	Additional Support Agreement dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, and Ohio Edison Company. (1987 Form 10-K, Exhibit 28-12)

(E) 10-91	Participation Agreement dated as of September 15, 1987, among Chrysler Consortium Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-13)

(E) 10-92	Amendment No. 1 dated as of February 1, 1988, to Participation Agreement dated as of September 15, 1987, among Chrysler Consortium Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-14)

(E) 10-93	Amendment No. 3 dated as of March 16, 1988 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-114)

(E) 10-94	Amendment No. 4 dated as of November 5, 1992 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-115)

(E) 10-95	Amendment No. 5 dated as of January 12, 1993 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-139)

(E) 10-96	Amendment No. 6 dated as of September 30, 1994 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-140)

(E) 10-97	Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, Lessor, and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-15)

(E) 10-98	Amendment No. 1 dated as of February 1, 1988, to Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, Lessor, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-16)

(E) 10-99	Amendment No. 2 dated as of November 5, 1992 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-118)

(E) 10-100	Amendment No. 3 dated as of January 12, 1993 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-119)

(E) 10-101	Amendment No. 4 dated as of September 30, 1994 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-145)

(E) 10-102	Ground Lease and Easement Agreement dated as of September 15, 1987, between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, Tenant. (1987 Form 10-K, Exhibit 28-17)

(E) 10-103	Trust Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and The First National Bank of Boston. (1987 Form 10-K, Exhibit 28-18)

(E) 10-104	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-19)

(E) 10-105	Supplemental Indenture No. 1 dated as of February 1, 1988 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with Chrysler Consortium Corporation and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-20)

(E) 10-106	Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-21)

(E) 10-107	Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-151)

(E) 10-108	Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-152)

(E) 10-109	Amendment No. 3 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-153)

(E) 10-110	Assignment, Assumption and Further Agreement dated as of September 15, 1987, among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, and Toledo Edison Company. (1987 Form 10-K, Exhibit 28-22)

(E) 10-111	Additional Support Agreement dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, and Ohio Edison Company. (1987 Form 10-K, Exhibit 28-23)

10-112	Operating Agreement for Bruce Mansfield Units Nos. 1, 2 and 3 dated as of June 1, 1976, and executed on September 15, 1987, by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 28-25)

10-113	OE Nuclear Capital Contribution Agreement by and between Ohio Edison Company and FirstEnergy Nuclear Generation Corp. (June 2005 Form 10-Q, Exhibit 10.1)

10-114	OE Fossil Purchase and Sale Agreement by and between Ohio Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (June 2005 Form 10-Q, Exhibit 10.2)

10-115	OE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and Ohio Edison Company. (Form S-4/A filed August 20, 2007 by FirstEnergy Solutions Corp., Exhibit 10.18)

10-116	Consent Decree dated March 18, 2005. (Form 8-K filed March 18, 2005 by FirstEnergy Corp., Exhibit 10.1)

10-117	Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and The Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer). (2005 Form 10-K, Exhibit 10-64)

10-118	Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and the FirstEnergy Operating Companies – Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company (Buyers). (2005 Form 10-K, Exhibit 10-65)


10-119	Revised Power Supply Agreement, dated December 8, 2006, among FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. (Form S-4/A dated August 20, 2007, Exhibit 10.34)

(A) 12-3	Consolidated ratios of earnings to fixed charges.

(A) 13-2	OE 2008 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed “filed” with the SEC.)

(A) 23-2	Consent of Independent Registered Public Accounting Firm.
	~~31.1~~
(A) 31-1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	~~31.2~~
(A) 31-2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).

(A) 32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.

(A)	Provided herein in electronic format as an exhibit.

(B)	Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.

(C)	Substantially similar documents have been entered into relating to three additional Owner Participants.

(D)	Substantially similar documents have been entered into relating to five additional Owner Participants.

(E)	Substantially similar documents have been entered into relating to two additional Owner Participants.

3. Exhibits – Common Exhibits for CEI and TE

~~Penelec~~

2-1	Agreement and Plan of Merger between Ohio Edison Company and Centerior Energy dated as of September 13, 1996. (Form S-4, Exhibit (2)-1, File No. 333-21011)

2-2	Merger Agreement by and among Centerior Acquisition Corp., FirstEnergy Corp and Centerior Energy Corp. (Form S-4, Exhibit (2)-3, File No. 333-21011)

10-1	CAPCO Administration Agreement dated November 1, 1971, as of September 14, 1967, among the CAPCO Group members regarding the organization and procedures for implementing the objectives of the CAPCO Group. (Amendment No. 1, Exhibit 5(p), File No. 2-42230)

10-2	Amendment No. 1, dated January 4, 1974, to CAPCO Administration Agreement among the CAPCO Group members. (File No. 2-68906, Exhibit 5(c)(3) filed by Ohio Edison Company)

10-3	Agreement for the Termination or Construction of Certain Agreement By and Among the CAPCO Group members, dated December 23, 1993 and effective as of September 1, 1980. (1993 Form 10-K, Exhibit 10b(4), File Nos. 1-9130, 1-2323 and 1-3583)

10-4	Second Amendment to the Bruce Mansfield Units 1, 2, and 3 Operating Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (Form 8-K/A filed August 2, 2007 by FirstEnergy Corp., Exhibit 10-11)

10-5	Amendment No. 6A dated as of December 1, 1991, to the Bond Guaranty dated as of October 1, 1973, by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (1991 Form 10-K filed by Ohio Edison Company, Exhibit 10-33)

10-6	Amendment No. 6B dated as of December 30, 1991, to the Bond Guaranty dated as of October 1, 1973 by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (1991 Form 10-K filed by Ohio Edison Company, Exhibit 10-34)

10-7	Form of Collateral Trust Indenture among CTC Beaver Valley Funding Corporation, The Cleveland Electric Illuminating Company, The Toledo Edison Company and Irving Trust Company, as Trustee. (File No. 33-18755, Exhibit 4(a))

10-8	Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10-10 above, including form of Secured Lease Obligation bond. (File No. 33-18755, Exhibit 4(b))

10-9	Form of Collateral Trust Indenture among Beaver Valley II Funding Corporation, The Cleveland Electric Illuminating Company and The Toledo Edison Company and The Bank of New York, as Trustee. (File No. 33-46665, Exhibit (4)(a))

10-10	Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10-12 above, including form of Secured Lease Obligation Bond. (File No. 33-46665, Exhibit (4)(b))

10-11	Form of Collateral Trust Indenture among CTC Mansfield Funding Corporation, Cleveland Electric, Toledo Edison and IBJ Schroder Bank & Trust Company, as Trustee. (File No. 33-20128, Exhibit 4(a))

10-12	Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10-14 above, including forms of Secured Lease Obligation bonds. (File No. 33-20128, Exhibit 4(b))

10-13	Form of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the limited partnership Owner Participant named therein, Lessor, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, Lessee. (File No. 33-18755, Exhibit 4(c))

10-14	Form of Amendment No. 1 to Facility Lease constituting Exhibit 10-16 above. (File No. 33-18755, Exhibit 4(e))

10-15	Form of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the corporate Owner Participant named therein, Lessor, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, Lessees. (File No. 33-18755, Exhibit 4(d))

10-16	Form of Amendment No. 1 to Facility Lease constituting Exhibit 10-18 above. (File No. 33-18755, Exhibit 4(f))

10-17	Form of Facility Lease dated as of September 30, 1987 between Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Lessor, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, Lessees. (File No. 33-20128, Exhibit 4(c))

10-18	Form of Amendment No. 1 to the Facility Lease constituting Exhibit 10-20 above. (File No. 33-20128, Exhibit 4(f))

10-19	Form of Participation Agreement dated as of September 15, 1987 among the limited partnership Owner Participant named therein, the Original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants, CTC Beaver Valley Fund Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees. (File No. 33-18755, Exhibit 28(a))

10-20	Form of Amendment No. 1 to Participation Agreement constituting Exhibit 10-22 above (File No. 33-18755, Exhibit 28(c))

10-21	Form of Participation Agreement dated as of September 15, 1987 among the corporate Owner Participant named therein, the Original Loan Participants listed in Schedule 1 thereto, as Owner Loan Participants, CTC Beaver Valley Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees. (File No. 33-18755, Exhibit 28(b))

10-22	Form of Amendment No. 1 to Participation Agreement constituting Exhibit 10-24 above (File No. 33-18755, Exhibit 28(d))

10-23	Form of Participation Agreement dated as of September 30, 1987 among the Owner Participant named therein, the Original Loan Participants listed in Schedule II thereto, as Owner Loan Participants, CTC Mansfield Funding Corporation, Meridian Trust Company, as Owner Trustee, IBJ Schroder Bank & Trust Company, as Indenture Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees. (File No. 33-0128, Exhibit 28(a))

10-24	Form of Amendment No. 1 to the Participation Agreement constituting Exhibit 10-26 above (File No. 33-20128, Exhibit 28(b))

10-25	Form of Ground Lease dated as of September 15, 1987 between Toledo Edison, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Tenant. (File No. 33-18755, Exhibit 28(e))

10-26	Form of Site Lease dated as of September 30, 1987 between Toledo Edison, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant. (File No. 33-20128, Exhibit 28(c))

10-27	Form of Site Lease dated as of September 30, 1987 between The Cleveland Electric Illuminating Company, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant. (File No. 33-20128, Exhibit 28(d))

10-28	Form of Amendment No. 1 to the Site Leases constituting Exhibits 10-29 and 10-30 above (File No. 33-20128, Exhibit 4(f))

10-29	Form of Assignment, Assumption and Further Agreement dated as of September 15, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, The Cleveland Electric Illuminating Company, Duquesne, Ohio Edison Company, Pennsylvania Power Company and The Toledo Edison Company. (File No. 33-18755, Exhibit 28(f))

10-30	Form of Additional Support Agreement dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein and The Toledo Edison Company. (File No. 33-18755, Exhibit 28(g))

10-31	Form of Support Agreement dated as of September 30, 1987 between Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, The Toledo Edison Company, The Cleveland Electric Illuminating Company, Duquesne, Ohio Edison Company and Pennsylvania Power Company. (File No. 33-20128, Exhibit 28(e))

10-32	Form of Indenture, Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between The Toledo Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Buyer. (File No. 33-18755, Exhibit 28(h))

10-33	Form of Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between The Toledo Edison Company, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Buyer. (File No. 33-20128, Exhibit 28(f))

10-34	Form of Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between The Cleveland Electric Illuminating Company, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Buyer. (File No. 33-20128, Exhibit 28(g))

10-35	Forms of Refinancing Agreement, including exhibits thereto, among the Owner Participant named therein, as Owner Participant, CTC Beaver Valley Funding Corporation, as Funding Corporation, Beaver Valley II Funding Corporation, as New Funding Corporation, The Bank of New York, as Indenture Trustee, The Bank of New York, as New Collateral Trust Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees. (File No. 33-46665, Exhibit (28)(e)(i))

10-36	Form of Amendment No. 2 to Facility Lease among Citicorp Lescaman, Inc., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (Form S-4 filed March 10, 1998, Exhibit 10(a), File No. 333-47651)

10-37	Form of Amendment No. 3 to Facility Lease among Citicorp Lescaman, Inc., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (Form S-4 filed March 10, 1998, Exhibit 10(b), File No. 333-47651)

10-38	Form of Amendment No. 2 to Facility Lease among US West Financial Services, Inc., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (Form S-4 filed March 10, 1998, Exhibit 10(c), File No. 333-47651)

10-39	Form of Amendment No. 3 to Facility Lease among US West Financial Services, Inc., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (Form S-4 filed March 10, 1998, Exhibit 10(d), File No. 333-47651)

10-40	Form of Amendment No. 2 to Facility Lease among Midwest Power Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. (Form S-4 filed March 10, 1998 by The Cleveland Electric Illuminating Company, Exhibit 10(e), File No. 333-47651)

10-41	Centerior Energy Corporation Equity Compensation Plan. (Form S-8 filed May 26, 1995 by Centerior Energy Corporation, Exhibit 99, File No. 33-59635)

10-42	Revised Power Supply Agreement, dated December 8, 2006, among FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. (Form S-4/A filed August 20, 2007 by FirstEnergy Solutions Corp., Exhibit 10.34)

3. Exhibits – CEI

3-1	Amended and Restated Articles of Incorporation of The Cleveland Electric Illuminating Company, Effective December 21, 2007. (2007 Form 10-K, Exhibit 3.3)

3-2	Amended and Restated Code of Regulations of The Cleveland Electric Illuminating Company, dated December 14, 2007. (2007 Form 10-K, Exhibit 3.4)

(B) 4-1	Mortgage and Deed of Trust between The Cleveland Electric Illuminating Company and Guaranty Trust Company of New York (now The Chase Manhattan Bank (National Association)), as Trustee, dated July 1, 1940. (File No. 2-4450, Exhibit 7(a))

	Supplemental Indentures between The Cleveland Electric Illuminating Company and the Trustee, supplemental to Exhibit 4-1, dated as follows:

4-1(a)	July 1, 1940 (File No. 2-4450, Exhibit 7(b))
4-1(b)	August 18, 1944 (File No. 2-9887, Exhibit 4(c))
4-1(c)	December 1, 1947 (File No. 2-7306, Exhibit 7(d))

4-1(d)	September 1, 1950 (File No. 2-8587, Exhibit 7(c))
4-1(e)	June 1, 1951 (File No. 2-8994, Exhibit 7(f))
4-1(f)	May 1, 1954 (File No. 2-10830, Exhibit 4(d))
4-1(g)	March 1, 1958 (File No. 2-13839, Exhibit 2(a)(4))
4-1(h)	April 1, 1959 (File No. 2-14753, Exhibit 2(a)(4))
4-1(i)	December 20, 1967 (File No. 2-30759, Exhibit 2(a)(4))
4-1(j)	January 15, 1969 (File No. 2-30759, Exhibit 2(a)(5))
4-1(k)	November 1, 1969 (File No. 2-35008, Exhibit 2(a)(4))
4-1(l)	June 1, 1970 (File No. 2-37235, Exhibit 2(a)(4))
4-1(m)	November 15, 1970 (File No. 2-38460, Exhibit 2(a)(4))
4-1(n)	May 1, 1974 (File No. 2-50537, Exhibit 2(a)(4))
4-1(o)	April 15, 1975 (File No. 2-52995, Exhibit 2(a)(4))
4-1(p)	April 16, 1975 (File No. 2-53309, Exhibit 2(a)(4))
4-1(q)	May 28, 1975 (Form 8-A filed June 5, 1975, Exhibit 2(c), File No. 1-2323)
4-1(r)	February 1, 1976 (1975 Form 10-K, Exhibit 3(d)(6), File No. 1-2323)
4-1(s)	November 23, 1976 (File No. 2-57375, Exhibit 2(a)(4))
4-1(t)	July 26, 1977 (File No. 2-59401, Exhibit 2(a)(4))
4-1(u)	September 7, 1977 (File No. 2-67221, Exhibit 2(a)(5))
4-1(v)	May 1, 1978 (June 1978 Form 10-Q, Exhibit 2(b), File No. 1-2323)
4-1(w)	September 1, 1979 (September 1979 Form 10-Q, Exhibit 2(a), File No. 1-2323)
4-1(x)	April 1, 1980 (September 1980 Form 10-Q, Exhibit 4(a)(2), File No. 1-2323)
4-1(y)	April 15, 1980 (September 1980 Form 10-Q, Exhibit 4(b), File No. 1-2323)
4-1(z)	May 28, 1980 (Amendment No. 1, Exhibit 2(a)(4), File No. 2-67221)
4-1(aa)	June 9, 1980 (September 1980 Form 10-Q, Exhibit 4(d), File No. 1-2323)
4-1(bb)	December 1, 1980 (1980 Form 10-K, Exhibit 4(b)(29), File No. 1-2323)
4-1(cc)	July 28, 1981 (September 1981 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(dd)	August 1, 1981 (September 1981 Form 10-Q, Exhibit 4(b), File No. 1-2323)
4-1(ee)	March 1, 1982 (Amendment No. 1, Exhibit 4(b)(3), File No. 2-76029)
4-1(ff)	July 15, 1982 (September 1982 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(gg)	September 1, 1982 (September 1982 Form 10-Q, Exhibit 4(a)(1), File No. 1-2323)
4-1(hh)	November 1, 1982 (September 1982 Form 10-Q, Exhibit (a)(2), File No. 1-2323)
4-1(ii)	November 15, 1982 (1982 Form 10-K, Exhibit 4(b)(36), File No. 1-2323)
4-1(jj)	May 24, 1983 (June 1983 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(kk)	May 1, 1984 (June 1984 Form 10-Q, Exhibit 4, File No. 1-2323)
4-1(ll)	May 23, 1984 (Form 8-K dated May 22, 1984, Exhibit 4, File No. 1-2323)
4-1(mm)	June 27, 1984 (Form 8-K dated June 11, 1984, Exhibit 4, File No. 1-2323)
4-1(nn)	September 4, 1984 (1984 Form 10-K, Exhibit 4b(41), File No. 1-2323)
4-1(oo)	November 14, 1984 (1984 Form 10 K, Exhibit 4b(42), File No. 1-2323)
4-1(pp)	November 15, 1984 (1984 Form 10-K, Exhibit 4b(43), File No. 1-2323)
4-1(qq)	April 15, 1985 (Form 8-K dated May 8, 1985, Exhibit 4(a), File No. 1-2323)
4-1(rr)	May 28, 1985 (Form 8-K dated May 8, 1985, Exhibit 4(b), File No. 1-2323)
4-1(ss)	August 1, 1985 (September 1985 Form 10-Q, Exhibit 4, File No. 1-2323)
4-1(tt)	September 1, 1985 (Form 8-K dated September 30, 1985, Exhibit 4, File No. 1-2323)
4-1(uu)	November 1, 1985 (Form 8-K dated January 31, 1986, Exhibit 4, File No. 1-2323)
4-1(vv)	April 15, 1986 (March 1986 Form 10-Q, Exhibit 4, File No. 1-2323)
4-1(ww)	May 14, 1986 (June 1986 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(xx)	May 15, 1986 (June 1986 Form 10-Q, Exhibit 4(b), File No. 1-2323)
4-1(yy)	February 25, 1987 (1986 Form 10-K, Exhibit 4b(52), File No. 1-2323)
4-1(zz)	October 15, 1987 (September 1987 Form 10-Q, Exhibit 4, File No. 1-2323)
4-1(aaa)	February 24, 1988 (1987 Form 10-K, Exhibit 4b(54), File No. 1-2323)
4-1(bbb)	September 15, 1988 (1988 Form 10-K, Exhibit 4b(55), File No. 1-2323)
4-1(ccc)	May 15, 1989 (File No. 33-32724, Exhibit 4(a)(2)(i))
4-1(ddd)	June 13, 1989 (File No. 33-32724, Exhibit 4(a)(2)(ii))
4-1(eee)	October 15, 1989 (File No. 33-32724, Exhibit 4(a)(2)(iii))
4-1(fff)	January 1, 1990 (1989 Form 10-K, Exhibit 4b(59), File No. 1-2323)
4-1(ggg)	June 1, 1990 (September 1990 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(hhh)	August 1, 1990 (September 1990 Form 10-Q, Exhibit 4(b), File No. 1-2323)
4-1(iii)	May 1, 1991 (June 1991 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(jjj)	May 1, 1992 (File No. 33-48845, Exhibit 4(a)(3))
4-1(kkk)	July 31, 1992 (File No. 33-57292, Exhibit 4(a)(3))
4-1(lll)	January 1, 1993 (1992 Form 10-K, Exhibit 4b(65), File No. 1-2323)
4-1(mmm)	February 1, 1993 (1992 Form 10-K, Exhibit 4b(66), File No. 1-2323)
4-1(nnn)	May 20, 1993 (Form 8-K dated July 14, 1993, Exhibit 4(a), File No. 1-2323)

4-1(ooo)	June 1, 1993 (Form 8-K dated July 14, 1993, Exhibit 4(b), File No. 1-2323)
4-1(ppp)	September 15, 1994 (September 1994 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(qqq)	May 1, 1995 (September 1995 Form 10-Q, Exhibit 4(a), File No. 1-2323)
4-1(rrr)	May 2, 1995 (September 1995 Form 10-Q, Exhibit 4(b), File No. 1-2323)
4-1(sss)	June 1, 1995 (September 1995 Form 10-Q, Exhibit 4(c), File No. 1-2323)
4-1(ttt)	July 15, 1995 (1995 Form 10-K, Exhibit 4b(73), File No. 1-2323)
4-1(uuu)	August 1, 1995 (1995 Form 10-K, Exhibit 4b(74), File No. 1-2323)
4-1(vvv)	June 15, 1997 (Form S-4, Exhibit 4(a), File No. 333-35931)
4-1(www)	October 15, 1997 (Form S-4, Exhibit 4(a), File No. 333-47651)
4-1(xxx)	June 1, 1998 (Form S-4, Exhibit 4b(77), File No. 333-72891)
4-1(yyy)	October 1, 1998 (Form S-4, Exhibit 4b(78), File No. 333-72891)
4-1(zzz)	October 1, 1998 (Form S-4, Exhibit 4b(79), File No. 333-72891)
4-1(aaaa)	February 24, 1999 (Form S-4, Exhibit 4b(80), File No. 333-72891)
4-1(bbbb)	September 29, 1999 (1999 Form 10-K, Exhibit 4b(81), File No. 1-2323)
4-1(cccc)	January 15, 2000 (1999 Form 10-K, Exhibit 4b(82), File No. 1-2323)
4-1(dddd)	May 15, 2002 (2002 Form 10-K, Exhibit 4b(83), File No. 1-2323)
4-1(eeee)	October 1, 2002 (2002 Form 10-K, Exhibit 4b(84), File No. 1-2323)
4-1(ffff)	Supplemental Indenture dated as of September 1, 2004 (September 2004 Form 10-Q, Exhibit 4-1(85), File No. 1-2323)
4-1(gggg)	Supplemental Indenture dated as of October 1, 2004 (September 2004 Form 10-Q, Exhibit 4-1(86), File No. 1-2323)
4-1(hhhh)	Supplemental Indenture dated as of April 1, 2005 (June 2005 Form 10-Q, Exhibit 4.1, File No. 1-2323)
4-1(iiii)	Supplemental Indenture dated as of July 1, 2005 (June 2005 Form 10-Q, Exhibit 4.2, File No. 1-2323)
4-1(jjjj)	Eighty-Ninth Supplemental Indenture, dated as of November 1, 2008 (relating to First Mortgage Bonds, 8.875% Series due 2018). (Form 8-K filed November 19, 2008, Exhibit 4.1)

4-2	Form of Note Indenture between The Cleveland Electric Illuminating Company and The Chase Manhattan Bank, as Trustee dated as of October 24, 1997. (Form S-4 filed March 10, 1998, File No. 333-47651, Exhibit 4(b))

4-2(a)	Form of Supplemental Note Indenture between The Cleveland Electric Illuminating Company and The Chase Manhattan Bank, as Trustee dated as of October 24, 1997. (Form S-4 filed March 10, 1998, File No. 333-47651, Exhibit 4(c))

4-3	Indenture dated as of December 1, 2003 between The Cleveland Electric Illuminating Company and JPMorgan Chase Bank, as Trustee. (2003 Form 10-K, Exhibit 4-1, File No. 1-02323)

4-3(a)	Officer’s Certificate (including the form of 5.95% Senior Notes due 2036), dated as of December 11, 2006. (Form 8-K filed December 12, 2006, Exhibit 4)

4-3(b)	Officer’s Certificate (including the form of 5.70% Senior Notes due 2017), dated as of March 27, 2007. (Form 8-K filed March 28, 2007, Exhibit 4)

10-1	Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(2))

10-2	Amendment No. 1 dated January 4, 1974 to Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-68906, Exhibit 5(c)(3))

10-3	CEI Nuclear Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company and FirstEnergy Nuclear Generation Corp. (June 2005 Form 10-Q, Exhibit 10.1)

10-4	CEI Fossil Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (June 2005 Form 10-Q, Exhibit 10.2)

10-5	CEI Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Cleveland Electric Illuminating Company. (Form S-4/A filed August 20, 2007 by FirstEnergy Solutions Corp., Exhibit 10.16)

10-6	CEI Nuclear Security Agreement, dated December 16, 2005, by and between FirstEnergy Nuclear Generation Corp. and The Cleveland Electric Illuminating Company. (Form S-4/A filed August 20, 2007 by FirstEnergy Solutions Corp., Exhibit 10.26)

10-7	Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and The Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer). (2005 Form 10-K, Exhibit 10-64)

10-8	Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and the FirstEnergy Operating Companies – Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company (Buyers). (2005 Form 10-K, Exhibit 10-66)

10-9	Mansfield Power Supply Agreement dated as of October 14, 2005 between The Cleveland Electric Illuminating Company and The Toledo Edison Company (Sellers) and FirstEnergy Generation Corp. (Buyer). (2005 Form 10-K, Exhibit 10-65)

(A) 12-4	Consolidated ratios of earnings to fixed charges.

(A) 13-2	CEI 2008 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed “filed” with the SEC.)

(A) 23-3	Consent of Independent Registered Public Accounting ~~Firm.~~Firm
	~~31.1~~
(A) 31-1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	~~31.2~~
(A) 31-2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).

(A) 32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.

(A)	Provided herein in electronic format as an exhibit.

(B)	Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, CEI has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of CEI, but hereby agrees to furnish to the Commission on request any such instruments.

3. Exhibits – TE

3-1	Amended and Restated Articles of Incorporation of The Toledo Edison Company, effective December 18, 2007. (2007 Form 10-K, Exhibit 3c)

3-2	Amended and Restated Code of Regulations of The Toledo Edison Company, dated December 14, 2007. (2007 Form 10-K, Exhibit 3d)

(B) 4-1	Indenture, dated as of April 1, 1947, between The Toledo Edison Company and The Chase National Bank of the City of New York (now The Chase Manhattan Bank (National Association)), as Trustee. (File No. 2-26908, Exhibit 2(b))

	Supplemental Indentures between The Toledo Edison Company and the Trustee, supplemental to Exhibit 4-1, dated as follows:

4-1(a)	September 1, 1948 (File No. 2-26908, Exhibit 2(d))
4-1(b)	April 1, 1949 (File No. 2-26908, Exhibit 2(e))
4-1(c)	December 1, 1950 (File No. 2-26908, Exhibit 2(f))
4-1(d)	March 1, 1954 (File No. 2-26908, Exhibit 2(g))
4-1(e)	February 1, 1956 (File No. 2-26908, Exhibit 2(h))
4-1(f)	May 1, 1958 (File No. 2-59794, Exhibit 5(g))
4-1(g)	August 1, 1967 (File No. 2-26908, Exhibit 2(c))
4-1(h)	November 1, 1970 (File No. 2-38569, Exhibit 2(c))
4-1(i)	August 1, 1972 (File No. 2-44873, Exhibit 2(c))
4-1(j)	November 1, 1973 (File No. 2-49428, Exhibit 2(c))
4-1(k)	July 1, 1974 (File No. 2-51429, Exhibit 2(c))

4-1(l)	October 1, 1975 (File No. 2-54627, Exhibit 2(c))
4-1(m)	June 1, 1976 (File No. 2-56396, Exhibit 2(c))
4-1(n)	October 1, 1978 (File No. 2-62568, Exhibit 2(c))
4-1(o)	September 1, 1979 (File No. 2-65350, Exhibit 2(c))
4-1(p)	September 1, 1980 (File No. 2-69190, Exhibit 4(s))
4-1(q)	October 1, 1980 (File No. 2-69190, Exhibit 4(c))
4-1(r)	April 1, 1981 (File No. 2-71580, Exhibit 4(c))
4-1(s)	November 1, 1981 (File No. 2-74485, Exhibit 4(c))
4-1(t)	June 1, 1982 (File No. 2-77763, Exhibit 4(c))
4-1(u)	September 1, 1982 (File No. 2-87323, Exhibit 4(x))
4-1(v)	April 1, 1983 (March 1983 Form 10-Q, Exhibit 4(c), File No. 1-3583)
4-1(w)	December 1, 1983 (1983 Form 10-K, Exhibit 4(x), File No. 1-3583)
4-1(x)	April 1, 1984 (File No. 2-90059, Exhibit 4(c))
4-1(y)	October 15, 1984 (1984 Form 10-K, Exhibit 4(z), File No. 1-3583)
4-1(z)	October 15, 1984 (1984 Form 10-K, Exhibit 4(aa), File No. 1-3583)
4-1(aa)	August 1, 1985 (File No. 33-1689, Exhibit 4(dd))
4-1(bb)	August 1, 1985 (File No. 33-1689, Exhibit 4(ee))
4-1(cc)	December 1, 1985 (File No. 33-1689, Exhibit 4(c))
4-1(dd)	March 1, 1986 (1986 Form 10-K, Exhibit 4b(31), File No. 1-3583)
4-1(ee)	October 15, 1987 (September 30, 1987 Form 10-Q, Exhibit 4, File No. 1-3583)
4-1(ff)	September 15, 1988 (1988 Form 10-K, Exhibit 4b(33), File No. 1-3583)
4-1(gg)	June 15, 1989 (1989 Form 10-K, Exhibit 4b(34), File No. 1-3583)
4-1(hh)	October 15, 1989 (1989 Form 10-K, Exhibit 4b(35), File No. 1-3583)
4-1(ii)	May 15, 1990 (June 30, 1990 Form 10-Q, Exhibit 4, File No. 1-3583)
4-1(jj)	March 1, 1991 (June 30, 1991 Form 10-Q, Exhibit 4(b), File No. 1-3583)
4-1(kk)	May 1, 1992 (File No. 33-48844, Exhibit 4(a)(3))
4-1(ll)	August 1, 1992 (1992 Form 10-K, Exhibit 4b(39), File No. 1-3583)
4-1(mm)	October 1, 1992 (1992 Form 10-K, Exhibit 4b(40), File No. 1-3583)
4-1(nn)	January 1, 1993 (1992 Form 10-K, Exhibit 4b(41), File No. 1-3583)
4-1(oo)	September 15, 1994 (September 1994 Form 10-Q, Exhibit 4(b), File No. 1-3583)
4-1(pp)	May 1, 1995 (September 1995 Form 10-Q, Exhibit 4(d), File No. 1-3583)
4-1(qq)	June 1, 1995 (September 1995 Form 10-Q, Exhibit 4(e), File No. 1-3583)
4-1(rr)	July 14, 1995 (September 1995 Form 10-Q, Exhibit 4(f), File No. 1-3583)
4-1(ss)	July 15, 1995 (September 1995 Form 10-Q, Exhibit 4(g), File No. 1-3583)
4-1(tt)	August 1, 1997 (1998 Form 10-K, Exhibit 4b(47), File No. 1-3583)
4-1(uu)	June 1, 1998 (1998 Form 10-K, Exhibit 4b (48), File No. 1-3583)
4-1(vv)	January 15, 2000 (1999 Form 10-K, Exhibit 4b(49), File No. 1-3583)
4-1(ww)	May 1, 2000 (2000 Form 10-K, Exhibit 4b(50), File No. 1-3583)
4-1(xx)	September 1, 2000 (2002 Form 10-K, Exhibit 4b(51), File No. 1-3583)
4-1(yy)	October 1, 2002 (2002 Form 10-K, Exhibit 4b(52), File No. 1-3583)
4-1(zz)	April 1, 2003 (2003 Form 10-K, Exhibit 4b(53), File No. 1-3583)
4-1(aaa)	September 1, 2004 (September 2004 10-Q, Exhibit 4.2.56, File No. 1-3583)
4-1(bbb)	April 1, 2005 (June 2005 10-Q, Exhibit 4.1, File No. 1-3583)

4-2	Indenture dated as of November 1, 2006, between The Toledo Edison Company and The Bank of New York Trust Company, N.A. (2006 Form 10-K, Exhibit 4-2)

4-2(a)	Officer’s Certificate (including the form of 6.15% Senior Notes due 2037), dated November 16, 2006. (Form 8-K filed November 16, 2006, Exhibit 4)

10-1	TE Nuclear Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Nuclear Generation Corp. (Purchaser). (June 2005 Form 10-Q, Exhibit 10.1)

10-2	TE Fossil Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (June 2005 Form 10-Q, Exhibit 10.2)

10-3	TE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Toledo Edison Company. (Form S-4/A filed August 20, 2007 by FirstEnergy Solutions Corp., Exhibit 10.24)

10-4	Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and The Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer). (2005 Form 10-K, Exhibit 10-64)

10-5	Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and the FirstEnergy Operating Companies – Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company (Buyers). (2005 Form 10-K, Exhibit 10-6)

10-6	Mansfield Power Supply Agreement dated as of October 14, 2005 between The Cleveland Electric Illuminating Company and The Toledo Edison Company (Sellers) and FirstEnergy Generation Corp. (Buyer). (2005 Form 10-K, Exhibit 10-65)

(A) 12-5	Consolidated ratios of earnings to fixed charges.

(A) 13-2	TE 2008 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed “filed” with the SEC.)

(A) 23-4	Consent of Independent Registered Public Accounting Firm

(A) 31-1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).

(A) 31-2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).

(A) 32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.

(A)	Provided herein in electronic format as an exhibit.

(B)	Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, TE has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of TE, but hereby agrees to furnish to the Commission on request any such instruments.

3. Exhibits – JCP&L

3-1	Amended and Restated Certificate of Incorporation of Jersey Central Power & Light Company, filed February 14, 2008. (2007 Form 10-K, Exhibit 3-D)

3-2	Amended and Restated Bylaws of Jersey Central Power & Light Company, dated January 9, 2008. (2007 Form 10-K, Exhibit 3-E)

4-1	Senior Note Indenture, dated as of July 1, 1999, between Jersey Central Power & Light Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee to United States Trust Company of New York. (Registration No. 333-78717, Exhibit 4-A)

4-1(a)	First Supplemental Indenture, dated October 31, 2007, between Jersey Central Power & Light Company, The Bank of New York, as resigning trustee, and The Bank of New York Trust Company, N.A., as successor trustee. (Registration No. 333-146968, Exhibit 4-2)

4-1(b)	Form of Jersey Central Power & Light Company 6.40% Senior Note due 2036. (Form 8-K filed May 12, 2006, Exhibit 10-1)

4-1(c)	Form of 7.35% Senior Notes due 2019. (Form 8-K filed January 27, 2009, Exhibit 4.1)

10-1	Indenture dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and The Bank of New York as Trustee. (Form 8-K filed August 10, 2006, Exhibit 4-1)

10-2	2006-A Series Supplement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and The Bank of New York as Trustee. (Form 8-K filed August 10, 2006, Exhibit 4-2)

10-3	Bondable Transition Property Sale Agreement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and Jersey Central Power & Light Company as Seller. (Form 8-K filed August 10, 2006, Exhibit 10-1)

10-4	Bondable Transition Property Service Agreement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and Jersey Central Power & Light Company as Servicer. (Form 8-K filed August 10, 2006, Exhibit 10-2)

10-5	Administration Agreement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and FirstEnergy Service Company as Administrator. (Form 8-K filed August 10, 2006, Exhibit 10-3)

(A) 12-6	Consolidated ratios of earnings to fixed charges.

(A) 13-2	JCP&L 2008 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed “filed” with SEC.)

(A) 23-5	Consent of Independent Registered Public Accounting Firm

(A) 31-1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).

(A) 31-2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).

(A) 32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.

(A)	Provided herein electronic format as an exhibit.

3. Exhibits - Met-Ed

3-1	Amended and Restated Articles of Incorporation of Metropolitan Edison Company, effective December 19, 2007. (2007 Form 10-K, Exhibit 3.9)

3-2	Amended and Restated Bylaws of Metropolitan Edison Company, dated December 14, 2007. (2007 Form 10-K, Exhibit 3.10)

4-1	Indenture of Metropolitan Edison Company, dated November 1, 1944, between Metropolitan Edison Company and United States Trust Company of New York, Successor Trustee, as amended and supplemented by fourteen supplemental indentures dated February 1, 1947 through May 1, 1960. (Metropolitan Edison Company’s Instruments of Indebtedness Nos. 1 to 14 inclusive, and 16, filed as part of Amendment No. 1 to 1959 Annual Report of GPU on Form U5S, File Nos. 30-126 and 1-3292)

4-1(a)	Supplemental Indenture of Metropolitan Edison Company, dated December 1, 1962. (Registration No. 2-59678, Exhibit 2-E(1))
4-1(b)	Supplemental Indenture of Metropolitan Edison Company, dated March 20, 1964. (Registration No. 2-59678, Exhibit 2-E(2))
4-1(c)	Supplemental Indenture of Metropolitan Edison Company, dated July 1, 1965. (Registration No. 2-59678, Exhibit 2-E(3))
4-1(d)	Supplemental Indenture of Metropolitan Edison Company, dated June 1, 1966. (Registration No. 2-24883, Exhibit 2-B-4))
4-1(e)	Supplemental Indenture of Metropolitan Edison Company, dated March 22, 1968. (Registration No. 2-29644, Exhibit 4-C-5)
4-1(f)	Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1968. (Registration No. 2-59678, Exhibit 2-E(6))
4-1(g)	Supplemental Indenture of Metropolitan Edison Company, dated August 1, 1969. (Registration No. 2-59678, Exhibit 2-E(7))
4-1(h)	Supplemental Indenture of Metropolitan Edison Company, dated November 1, 1971. (Registration No. 2-59678, Exhibit 2-E(8))
4-1(i)	Supplemental Indenture of Metropolitan Edison Company, dated May 1, 1972. (Registration No. 2-59678, Exhibit 2-E(9))
4-1(j)	Supplemental Indenture of Metropolitan Edison Company, dated December 1, 1973. (Registration No. 2-59678, Exhibit 2-E(10))

4-1(k)	Supplemental Indenture of Metropolitan Edison Company, dated October 30, 1974. (Registration No. 2-59678, Exhibit 2-E(11))
4-1(l)	Supplemental Indenture of Metropolitan Edison Company, dated October 31, 1974. (Registration No. 2-59678, Exhibit 2-E(12))
4-1(m)	Supplemental Indenture of Metropolitan Edison Company, dated March 20, 1975. (Registration No. 2-59678, Exhibit 2-E(13))
4-1(n)	Supplemental Indenture of Metropolitan Edison Company, dated September 25, 1975. (Registration No. 2-59678, Exhibit 2-E(15))
4-1(o)	Supplemental Indenture of Metropolitan Edison Company, dated January 12, 1976. (Registration No. 2-59678, Exhibit 2-E(16))
4-1(p)	Supplemental Indenture of Metropolitan Edison Company, dated March 1, 1976. (Registration No. 2-59678, Exhibit 2-E(17))
4-1(q)	Supplemental Indenture of Metropolitan Edison Company, dated September 28, 1977. (Registration No. 2-62212, Exhibit 2-E(18))
4-1(r)	Supplemental Indenture of Metropolitan Edison Company, dated January 1, 1978. (Registration No. 2-62212, Exhibit 2-E(19))
4-1(s)	Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1978. (Registration No. 33-48937, Exhibit 4-A(19))
4-1(t)	Supplemental Indenture of Metropolitan Edison Company, dated June 1, 1979. (Registration No. 33-48937, Exhibit 4-A(20))
4-1(u)	Supplemental Indenture of Metropolitan Edison Company, dated January 1, 1980. (Registration No. 33-48937, Exhibit 4-A(21))
4-1(v)	Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1981. (Registration No. 33-48937, Exhibit 4-A(22))
4-1(w)	Supplemental Indenture of Metropolitan Edison Company, dated September 10, 1981. (Registration No. 33-48937, Exhibit 4-A(23))
4-1(x)	Supplemental Indenture of Metropolitan Edison Company, dated December 1, 1982. (Registration No. 33-48937, Exhibit 4-A(24))
4-1(y)	Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1983. (Registration No. 33-48937, Exhibit 4-A(25))
4-1(z)	Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1984. (Registration No. 33-48937, Exhibit 4-A(26))
4-1(aa)	Supplemental Indenture of Metropolitan Edison Company, dated March 1, 1985. (Registration No. 33-48937, Exhibit 4-A(27))
4-1(bb)	Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1985. (Registration No. 33-48937, Exhibit 4-A(28))
4-1(cc)	Supplemental Indenture of Metropolitan Edison Company, dated June 1, 1988. (Registration No. 33-48937, Exhibit 4-A(29))
4-1(dd)	Supplemental Indenture of Metropolitan Edison Company, dated April 1, 1990. (Registration No. 33-48937, Exhibit 4-A(30))
4-1(ee)	Amendment dated May 22, 1990 to Supplemental Indenture of Metropolitan Edison Company, dated April 1, 1990. (Registration No. 33-48937, Exhibit 4-A(31))
4-1(ff)	Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1992. (Registration No. 33-48937, Exhibit 4-A(32)(a))
4-1(gg)	Supplemental Indenture of Metropolitan Edison Company, dated December 1, 1993. (1993 Annual Report of GPU on Form U5S, Exhibit C-58, File No. 30-126)
4-1(hh)	Supplemental Indenture of Metropolitan Edison Company, dated July 15, 1995. (1995 Form 10-K, Exhibit 4-B-35, File No. 1-446)
4-1(ii)	Supplemental Indenture of Metropolitan Edison Company, dated August 15, 1996. (1996 Form 10-K, Exhibit 4-B-35, File No. 1-446)
4-1(jj)	Supplemental Indenture of Metropolitan Edison Company, dated May 1, 1997. (1997 Form 10-K, Exhibit 4-B-36, File No. 1-446)
4-1(kk)	Supplemental Indenture of Metropolitan Edison Company, dated July 1, 1999. (1999 Form 10-K, Exhibit 4-B-38, File No. 1-446)
4-1(ll)	Supplemental Indenture of Metropolitan Edison Company, dated May 1, 2001. (2001 Form 10-K, Exhibit 4-5, File No. 1-446)
4-1(mm)	Supplemental Indenture of Metropolitan Edison Company, dated March 1, 2003. (2003 Form 10-K, Exhibit 4-10, File No. 1-446)

4-2	Senior Note Indenture between Metropolitan Edison Company and United States Trust Company of New York, dated July 1, 1999. (1999 Annual Report of GPU on Form U5S, Exhibit C-154, File No. 30-126)

4-2(a)	Form of Metropolitan Edison Company 7.70% Senior Notes due 2019. (Form 8-K filed January 21, 2009, Exhibit 4.1)

(A) 12-7	Consolidated ratios of earnings to fixed charges.

(A) 13-2	Met-Ed 2008 Annual Report to Stockholders (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed “filed” with SEC.)

(A) 23-6	Consent of Independent Registered Public Accounting Firm

(A) 31-1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).

(A) 31-2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).

(A) 32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.

(A)	Provided herein electronic format as an exhibit.

3. Exhibits - Penelec

3-1	Amended and Restated Articles of Incorporation of Pennsylvania Electric Company, effective December 19, 2007. (2007 Form 10-K, Exhibit 3.11)

3-2	Amended and Restated Bylaws of Pennsylvania Electric Company, dated December 14, 2007. (2007 Form 10-K, Exhibit 3.12)

4-1	Mortgage and Deed of Trust of Pennsylvania Electric Company, dated January 1, 1942, between Pennsylvania Electric Company and United States Trust Company of New York, Successor Trustee, and indentures supplemental thereto dated March 7, 1942 through May 1, 1960 – (Pennsylvania Electric Company’s Instruments of Indebtedness Nos. 1-20, inclusive, filed as a part of Amendment No. 1 to 1959 Annual Report of GPU on Form U5S, File Nos. 30-126 and 1-3292)

4-1(a)	Supplemental Indentures to Mortgage and Deed of Trust of Pennsylvania Electric Company, dated May 1, 1961 through December 1, 1977. (Registration No. 2-61502, Exhibit 2-D(1) to 2-D(19))
4-1(b)	Supplemental Indenture of Pennsylvania Electric Company, dated June 1, 1978. (Registration No. 33-49669, Exhibit 4-A(2))
4-1(c)	Supplemental Indenture of Pennsylvania Electric Company dated June 1, 1979. (Registration No. 33-49669, Exhibit 4-A(3))
4-1(d)	Supplemental Indenture of Pennsylvania Electric Company, dated September 1, 1984. (Registration No. 33-49669, Exhibit 4-A(4))
4-1(e)	Supplemental Indenture of Pennsylvania Electric Company, dated December 1, 1985. (Registration No. 33-49669, Exhibit 4-A(5))
4-1(f)	Supplemental Indenture of Pennsylvania Electric Company, dated December 1, 1986. (Registration No. 33-49669, Exhibit 4-A(6))
4-1(g)	Supplemental Indenture of Pennsylvania Electric Company, dated May 1, 1989. (Registration No. 33-49669, Exhibit 4-A(7))
4-1(h)	Supplemental Indenture of Pennsylvania Electric Company, dated December 1, 1990. (Registration No. 33-45312, Exhibit 4-A(8))
4-1(i)	Supplemental Indenture of Pennsylvania Electric Company, dated March 1, 1992. (Registration No. 33-45312, Exhibit 4-A(9))
4-1(j)	Supplemental Indenture of Pennsylvania Electric Company, dated June 1, 1993. (1993 Annual Report of GPU on Form U5S, Exhibit C-73, File No. 30-126)
4-1(k)	Supplemental Indenture of Pennsylvania Electric Company, dated November 1, 1995. (1995 Form 10-K, Exhibit 4-C-11, File No. 1-3522)
4-1(l)	Supplemental Indenture of Pennsylvania Electric Company, dated August 15, 1996. (1996 Form 10-K, Exhibit 4-C-12, File No. 1-3522)
4-1(m)	Supplemental Indenture of Pennsylvania Electric Company, dated May 1, 2001. (2001 Form 10-K, Exhibit 4-C-16)

4-2	Senior Note Indenture between Pennsylvania Electric Company and United States Trust Company of New York, dated April 1, 1999. (1999 Form 10-K, Exhibit 4-C-13, File No. 1-3522)

4-2(a)	Form of Pennsylvania Electric Company 6.05% Senior Notes due 2017. (Form 8-K filed August 31, 2007, Exhibit 4.1)

(A) 12-8	Consolidated ratios of earnings to fixed charges.

(A) 13-2	Penelec 2008 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed “filed” with SEC)

(A) 23-7	Consent of Independent Registered Public Accounting Firm.

(A) 31-1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).

(A) 31-2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).

(A) 32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350.

(A)	Provided here in electronic format as an exhibit.

3. Exhibits - Common Exhibits for FES, Met-Ed and Penelec

10-1	Notice of Termination Tolling Agreement dated as of April 7, 2006; Restated Partial Requirements Agreement, dated January 1, 2003, by and among, Metropolitan Edison Company, Pennsylvania Electric Company, The Waverly Electric Power and Light Company and FirstEnergy Solutions Corp., as amended by a First Amendment to Restated Requirements Agreement, dated August 29, 2003 and by a Second Amendment to Restated Requirements Agreement, dated June 8, 2004 (“Partial Requirements Agreement”). (March 2006 Form 10-Q filed by Metropolitan Edison Company, Exhibit 10-5)

10-2	Third Restated Partial Requirements Agreement, among Metropolitan Edison Company, Pennsylvania Electric Company, a Pennsylvania corporation, The Waverly Electric Power and Light Company and FirstEnergy Solutions Corp., dated November 1, 2008. (September 2008 Form 10-Q filed by Metropolitan Edison Company, Exhibit 10-2)

3. Exhibits - Common Exhibits for FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec

10-1	$2,750,000,000 Credit Agreement dated as of August 24, 2006 among FirstEnergy Corp., FirstEnergy Solutions Corp., American Transmission Systems, Inc., Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company, as Borrowers, the banks party thereto, the fronting banks party thereto and the swing line lenders party thereto. (Form 8-K filed August 24, 2006, Exhibit 10-1)

10-2	Consent and Amendment to $2,750,000,000 Credit Agreement dated November 2, 2007. (2007 Form 10-K, Exhibit 10-2)

Report of Independent Registered Public Accounting Firm

Financial Statement Schedule

To the Stockholders and Board of Directors of

FirstEnergy Corp.:

Our audits of the consolidated financial statements and of the effectiveness of internal control over financial reporting referred to in our report dated February 24, 2009 appearing in the 2008 Annual Report to Stockholders of FirstEnergy Corp. (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 24, 2009

8873

Report of Independent Registered Public Accounting Firm

~~SIGNATURES~~on

Financial Statement Schedule

To the Stockholder and Board of Directors of

FirstEnergy Solutions Corp.:

Our audits of the consolidated financial statements referred to in our report dated February 24, 2009 appearing in the 2008 Annual Report to Stockholders of FirstEnergy Solutions Corp. (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 24, 2009

Report of Independent Registered Public Accounting Firm

Financial Statement Schedule

To the Stockholder and Board of Directors of

Ohio Edison Company:

Our audits of the consolidated financial statements referred to in our report dated February 24, 2009 appearing in the 2008 Annual Report to Stockholders of Ohio Edison Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 24, 2009

Report of Independent Registered Public Accounting Firm

Financial Statement Schedule

To the Stockholder and Board of Directors of

The Cleveland Electric Illuminating Company:

Our audits of the consolidated financial statements referred to in our report dated February 24, 2009 appearing in the 2008 Annual Report to Stockholders of The Cleveland Electric Illuminating Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 24, 2009

Report of Independent Registered Public Accounting Firm

Financial Statement Schedule

To the Stockholder and Board of Directors of

The Toledo Edison Company:

Our audits of the consolidated financial statements referred to in our report dated February 24, 2009 appearing in the 2008 Annual Report to Stockholders of The Toledo Edison Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 24, 2009

Report of Independent Registered Public Accounting Firm

Financial Statement Schedule

To the Stockholder and Board of Directors of

Jersey Central Power & Light Company:

Our audits of the consolidated financial statements referred to in our report dated February 24, 2009 appearing in the 2008 Annual Report to Stockholders of Jersey Central Power & Light Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 24, 2009

Report of Independent Registered Public Accounting Firm

Financial Statement Schedule

To the Stockholder and Board of Directors of

Metropolitan Edison Company:

Our audits of the consolidated financial statements referred to in our report dated February 24, 2009 appearing in the 2008 Annual Report to Stockholders of Metropolitan Edison Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 24, 2009

Report of Independent Registered Public Accounting Firm

Financial Statement Schedule

To the Stockholder and Board of Directors of

Pennsylvania Electric Company:

Our audits of the consolidated financial statements referred to in our report dated February 24, 2009 appearing in the 2008 Annual Report to Stockholders of Pennsylvania Electric Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 24, 2009

SCHEDULE II

FIRSTENERGY CORP.

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

			Additions
					Charged
	Beginning		Charged		to Other						Ending
Description	Balance		to Income		Accounts			Deductions			Balance
	(In thousands)
Year Ended December 31, 2008:

Accumulated provision for
uncollectible accounts – customers	$	35,567	$	48,297	$	31,308	(a)	$	87,325	(b)	$	27,847
– other	$	21,924	$	11,339	$	3,189	(a)	$	27,285	(b)	$	9,167

Loss carryforward
tax valuation reserve	$	30,616	$	1,435	$	(4,757	)	$	-		$	27,294


Year Ended December 31, 2007:

Accumulated provision for
uncollectible accounts – customers	$	43,214	$	53,522	$	50,165	(a)	$	111,334	(b)	$	35,567
– other	$	23,964	$	4,933	$	406	(a)	$	7,379	(b)	$	21,924

Loss carryforward
tax valuation reserve	$	415,531	$	8,819	$	(393,734	)	$	-		$	30,616


Year Ended December 31, 2006:

Accumulated provision for
uncollectible accounts – customers	$	37,733	$	60,461	$	34,259	(a)	$	89,239	(b)	$	43,214
– other	$	26,566	$	3,956	$	2,554	(a)	$	9,112	(b)	$	23,964

Loss carryforward
tax valuation reserve	$	402,142	$	-	$	13,389		$	-		$	415,531



(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

SCHEDULE II

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

			Additions
						Charged
	Beginning		Charged			to Other						Ending
Description	Balance		to Income			Accounts			Deductions			Balance
	(In thousands)
Year Ended December 31, 2008:

Accumulated provision for
uncollectible accounts – customers	$	8,072	$	(2,174	)	$	110	(a)	$	109	(b)	$	5,899
– other	$	9	$	4,374		$	2,541	(a)	$	109	(b)	$	6,815


Year Ended December 31, 2007:

Accumulated provision for
uncollectible accounts – customers	$	7,938	$	94		$	532	(a)	$	492	(b)	$	8,072
– other	$	5,593	$	9		$	-	(a)	$	5,593	(b)	$	9


Year Ended December 31, 2006:

Accumulated provision for
uncollectible accounts – customers	$	11,531	$	2,244		$	789	(a)	$	6,626	(b)	$	7,938
– other	$	5,599	$	15		$	7	(a)	$	28	(b)	$	5,593




(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

SCHEDULE II

OHIO EDISON COMPANY

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

			Additions
					Charged
	Beginning		Charged		to Other						Ending
Description	Balance		to Income		Accounts			Deductions			Balance
	(In thousands)
Year Ended December 31, 2008:

Accumulated provision for
uncollectible accounts – customers	$	8,032	$	12,179	$	10,027	(a)	$	24,173	(b)	$	6,065
– other	$	5,639	$	16,618	$	394	(a)	$	22,644	(b)	$	7


Year Ended December 31, 2007:

Accumulated provision for
uncollectible accounts – customers	$	15,033	$	10,513	$	30,234	(a)	$	47,748	(b)	$	8,032
– other	$	1,985	$	4,117	$	(240	) (a)	$	223	(b)	$	5,639


Year Ended December 31, 2006:

Accumulated provision for
uncollectible accounts – customers	$	7,619	$	22,466	$	11,817	(a)	$	26,869	(b)	$	15,033
– other	$	4	$	2,218	$	473	(a)	$	710	(b)	$	1,985




(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

SCHEDULE II

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

			Additions
						Charged
	Beginning		Charged			to Other						Ending
Description	Balance		to Income			Accounts			Deductions			Balance
	(In thousands)
Year Ended December 31, 2008:

Accumulated provision for
uncollectible accounts – customers	$	7,540	$	11,323		$	9,179	(a)	$	22,126	(b)	$	5,916
– other	$	433	$	(183	)	$	30	(a)	$	269	(b)	$	11


Year Ended December 31, 2007:		��

Accumulated provision for
uncollectible accounts – customers	$	6,783	$	17,998		$	7,842	(a)	$	25,083	(b)	$	7,540
– other	$	-	$	431		$	124	(a)	$	122	(b)	$	433


Year Ended December 31, 2006:

Accumulated provision for
uncollectible accounts – customers	$	5,180	$	14,890		$	10,067	(a)	$	23,354	(b)	$	6,783
– other	$	-	$	22		$	138	(a)	$	160	(b)	$	-




(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

SCHEDULE II

THE TOLEDO EDISON COMPANY

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

			Additions
						Charged
	Beginning		Charged			to Other						Ending
Description	Balance		to Income			Accounts			Deductions			Balance
	(In thousands)
Year Ended December 31, 2008:

Accumulated provision for
uncollectible accounts	$	615	$	(247	)	$	121	(a)	$	286	(b)	$	203

Year Ended December 31, 2007:

Accumulated provision for
uncollectible accounts	$	430	$	361		$	13	(a)	$	189		$	615

Year Ended December 31, 2006:

Accumulated provision for
uncollectible accounts	$	-	$	440		$	118	(a)	$	128	(b)	$	430




(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

SCHEDULE II

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

			Additions
						Charged
	Beginning		Charged			to Other						Ending
Description	Balance		to Income			Accounts			Deductions			Balance
	(In thousands)
Year Ended December 31, 2008:

Accumulated provision for
uncollectible accounts – customers	$	3,691	$	10,377		$	3,504	(a)	$	14,342	(b)	$	3,230
– other	$	-	$	44		$	24	(a)	$	23	(b)	$	45


Year Ended December 31, 2007:

Accumulated provision for
uncollectible accounts – customers	$	3,524	$	8,563		$	4,049	(a)	$	12,445	(b)	$	3,691
– other	$	-	$	-		$	-	(a)	$	-	(b)	$	-


Year Ended December 31, 2006:

Accumulated provision for
uncollectible accounts – customers	$	3,830	$	4,945		$	4,643	(a)	$	9,894	(b)	$	3,524
– other	$	204	$	(201	)	$	866	(a)	$	869	(b)	$	-




(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

SCHEDULE II

METROPOLITAN EDISON COMPANY

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

			Additions
					Charged
	Beginning		Charged		to Other						Ending
Description	Balance		to Income		Accounts			Deductions			Balance
	(In thousands)
Year Ended December 31, 2008:

Accumulated provision for
uncollectible accounts – customers	$	4,327	$	9,004	$	3,729	(a)	$	13,444	(b)	$	3,616
– other	$	1	$	19	$	21	(a)	$	41	(b)	$	-


Year Ended December 31, 2007:

Accumulated provision for
uncollectible accounts – customers	$	4,153	$	9,971	$	3,548	(a)	$	13,345	(b)	$	4,327
– other	$	2	$	245	$	18		$	264		$	1


Year Ended December 31, 2006:

Accumulated provision for
uncollectible accounts – customers	$	4,352	$	7,070	$	4,108	(a)	$	11,377	(b)	$	4,153
– other	$	-	$	15	$	36	(a)	$	49	(b)	$	2




(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

SCHEDULE II

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

			Additions
					Charged
	Beginning		Charged		to Other						Ending
Description	Balance		to Income		Accounts			Deductions			Balance
	(In thousands)
Year Ended December 31, 2008:

Accumulated provision for
uncollectible accounts – customers	$	3,905	$	7,589	$	4,758	(a)	$	13,131	(b)	$	3,121
– other	$	105	$	57	$	36	(a)	$	133	(b)	$	65


Year Ended December 31, 2007:

Accumulated provision for
uncollectible accounts – customers	$	3,814	$	8,351	$	3,958	(a)	$	12,218	(b)	$	3,905
– other	$	3	$	181	$	3	(a)	$	82	(b)	$	105


Year Ended December 31, 2006:

Accumulated provision for
uncollectible accounts – customers	$	4,184	$	6,381	$	4,368	(a)	$	11,119	(b)	$	3,814
– other	$	2	$	105	$	173	(a)	$	277	(b)	$	3




(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, ~~each Registrant~~the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

~~November 25, 2008~~

	~~OHIO EDISON COMPANY~~
	~~Registrant~~FIRSTENERGY CORP.

	~~THE CLEVELAND ELECTRIC~~
	~~ILLUMINATING COMPANY~~
	~~Registrant~~
BY: /s/Anthony J. Alexander
	~~THE TOLEDO EDISON COMPANY~~Anthony J. Alexander
	~~Registrant~~

	~~PENNSYLVANIA ELECTRIC COMPANY~~
	~~Registrant~~President and Chief Executive Officer

	~~/s/ Harvey L. Wagner~~
	~~Harvey L. Wagner~~
	~~Vice President and Controller~~

Date: February 24, 2009

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:



/s/ George M. Smart		/s/ Anthony J. Alexander
George M. Smart		Anthony J. Alexander
Chairman of the Board		President and Chief Executive Officer
		and Director (Principal Executive Officer)



/s/ Richard H. Marsh		/s/ Harvey L. Wagner
Richard H. Marsh		Harvey L. Wagner
Senior Vice President and Chief Financial		Vice President, Controller and Chief Accounting
Officer (Principal Financial Officer)		Officer (Principal Accounting Officer)



/s/ Paul T. Addison		/s/ Ernest J. Novak, Jr.
Paul T. Addison		Ernest J. Novak, Jr.
Director		Director



/s/ Michael J. Anderson		/s/ Catherine A. Rein
Michael J. Anderson		Catherine A. Rein
Director		Director



/s/ Carol A. Cartwright		/s/ Wes M. Taylor
Carol A. Cartwright		Wes M. Taylor
Director		Director



/s/ William T. Cottle		/s/ Jesse T. Williams, Sr.
William T. Cottle		Jesse T. Williams, Sr.
Director		Director



/s/ Robert B. Heisler, Jr.
Robert B. Heisler, Jr.
Director

Date: February 24, 2009

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	FIRSTENERGY SOLUTIONS CORP.


	BY: /s/ Donald R. Schneider
	Donald R. Schneider
	President

Date: February 24, 2009

/s/ Donald R. Schneider		/s/ Richard H. Marsh
Donald R. Schneider		Richard H. Marsh
President		Senior Vice President and Chief
(Principal Executive Officer)		Financial Officer and Director
		(Principal Financial Officer)



/s/ Anthony J. Alexander		/s/ Harvey L. Wagner
Anthony J. Alexander		Harvey L. Wagner
Director		Vice President and Controller
		(Principal Accounting Officer)



/s/ Gary R. Leidich
Gary R. Leidich
Director

Date: February 24, 2009

SIGNATURES

	OHIO EDISON COMPANY


	BY: /s/ Richard R. Grigg
	Richard R. Grigg
	President

Date: February 24, 2009

/s/ Anthony J. Alexander		/s/ Richard R. Grigg
Anthony J. Alexander		Richard R. Grigg
Director		President and Director
		(Principal Executive Officer)



/s/ Richard H. Marsh		/s/ Harvey L. Wagner
Richard H. Marsh		Harvey L. Wagner
Senior Vice President and Chief		Vice President and Controller
Financial Officer and Director		(Principal Accounting Officer)
(Principal Financial Officer)

Date: February 24, 2009

SIGNATURES

	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY


	BY: /s/ Richard R. Grigg
	Richard R. Grigg
	President

Date: February 24, 2009

/s/ Anthony J. Alexander		/s/ Richard R. Grigg
Anthony J. Alexander		Richard R. Grigg
Director		President and Director
		(Principal Executive Officer)




/s/ Richard H. Marsh		/s/ Harvey L. Wagner
Richard H. Marsh		Harvey L. Wagner
Senior Vice President and Chief		Vice President and Controller
Financial Officer and Director		(Principal Accounting Officer)
(Principal Financial Officer)

Date: February 24, 2009

SIGNATURES

	THE TOLEDO EDISON COMPANY


	BY: /s/ Richard R. Grigg
	Richard R. Grigg
	President

Date: February 24, 2009

/s/ Anthony J. Alexander		/s/ Richard R. Grigg
Anthony J. Alexander		Richard R. Grigg
Director		President and Director
		(Principal Executive Officer)




/s/ Richard H. Marsh		/s/ Harvey L. Wagner
Richard H. Marsh		Harvey L. Wagner
Senior Vice President and Chief		Vice President and Controller
Financial Officer and Director		(Principal Accounting Officer)
(Principal Financial Officer)

Date: February 24, 2009

SIGNATURES

	JERSEY CENTRAL POWER & LIGHT COMPANY


	BY: /s/ Stephen E. Morgan
	Stephen E. Morgan
	President

Date: February 24, 2009

/s/ Stephen E. Morgan		/s/ Paulette R. Chatman
Stephen E. Morgan		Paulette R. Chatman
President and Director (Principal Executive Officer)		Controller (Principal Financial and Accounting Officer)




/s/ Richard R. Grigg		/s/ Gelorma E. Persson
Richard R. Grigg		Gelorma E. Persson
Director		Director




/s/ Charles E. Jones		/s/ Jesse T. Williams, Sr.
Charles E. Jones		Jesse T. Williams, Sr.
Director		Director




/s/ Mark A. Julian
Mark A. Julian
Director

Date: February 24, 2009

SIGNATURES

	METROPOLITAN EDISON COMPANY


	BY: /s/ Richard R. Grigg
	Richard R. Grigg
	President

Date: February 24, 2009

/s/ Richard R. Grigg		/s/ Richard H. Marsh
Richard R. Grigg		Richard H. Marsh
President and Director		Senior Vice President and Chief
(Principal Executive Officer)		Financial Officer
		(Principal Financial Officer)



/s/ Ronald P. Lantzy		/s/ Harvey L. Wagner
Ronald P. Lantzy		Harvey L. Wagner
Regional President and Director		Vice President and Controller
		(Principal Accounting Officer)


/s/ Randy Scilla
Randy Scilla
Assistant Treasurer and Director

Date: February 24, 2009

SIGNATURES

	PENNSYLVANIA ELECTRIC COMPANY


	BY: /s/ Richard R. Grigg
	Richard R. Grigg
	President

Date: February 24, 2009

/s/ Richard R. Grigg		/s/ Richard H. Marsh
Richard R. Grigg		Richard H. Marsh
President and Director		Senior Vice President and Chief
(Principal Executive Officer)		Financial Officer
		(Principal Financial Officer)



/s/ James R. Napier, Jr.		/s/ Harvey L. Wagner
James R. Napier, Jr.		Harvey L. Wagner
Regional President and Director		Vice President and Controller
		(Principal Accounting Officer)


/s/ Randy Scilla
Randy Scilla
Assistant Treasurer and Director

Date: February 24, 2009

Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.

333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

333-145140-01	FIRSTENERGY SOLUTIONS CORP.	31-1560186
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3583	THE TOLEDO EDISON COMPANY	34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3141	JERSEY CENTRAL POWER & LIGHT COMPANY	21-0485010
	(A New Jersey Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3522	PENNSYLVANIA ELECTRIC COMPANY	25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

		Name of Each Exchange
Registrant	Title of Each Class	on Which Registered

FirstEnergy Corp.	Common Stock, $0.10 par value	New York Stock Exchange

Yes (X) No ( )	FirstEnergy Corp.
Yes ( ) No (X)	FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company

Yes (X)No ( )	~~The Cleveland Electric Illuminating Company and The Toledo Edison Company~~FirstEnergy Solutions Corp.
Yes ( ) No (X)	FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company

Yes (X) No ( )	FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company
Yes ( ) No (X)	~~The Cleveland Electric Illuminating Company and The Toledo Edison Company~~FirstEnergy Solutions Corp.

Large ~~Accelerated Filer~~accelerated filer ~~( )~~ (X)	~~N/A~~FirstEnergy Corp.
Accelerated ~~Filer~~filer ( )	N/A
Non-accelerated ~~Filer~~filer (do not check if a ~~Smaller Reporting Company)~~smaller reporting company) (X)	FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company

		OUTSTANDING
CLASS		AS OF FEBRUARY ~~28, 2008~~24, 2009
FirstEnergy Corp., $.10 par value		304,835,407
FirstEnergy Solutions Corp., no par value		7
Ohio Edison Company, no par value		60
The Cleveland Electric Illuminating Company, no par value		67,930,743
The Toledo Edison Company, $5 par value		29,402,054
Jersey Central Power & Light Company, $10 par value		13,628,447
Metropolitan Edison Company, no par value		859,500
Pennsylvania Electric Company, $20 par value		4,427,577

		PART OF FORM 10-K INTO WHICH
DOCUMENT		DOCUMENT IS INCORPORATED

FirstEnergy Corp. Annual Report to Stockholders for
the fiscal year ended December 31, ~~2007~~2008		Part II

Proxy Statement for ~~2008~~2009 Annual Meeting of Stockholders
to be held May ~~20, 2008~~19, 2009		Part III

~~Contents~~		~~Page~~

~~Glossary of Terms~~		~~ii-iv~~

~~Part II. Item 8. Financial Statements and Supplementary Data.~~		1

~~Ohio Edison Company~~

	~~Report of Independent Registered Public Accounting Firm~~	2
	~~Consolidated Statements of Income~~	3
	~~Consolidated Balance Sheets~~	4
	~~Consolidated Statements of Capitalization~~	5
	~~Consolidated Statements of Common Stockholder’s Equity~~	6
	~~Consolidated Statements of Cash Flows~~	7

~~The Cleveland Electric Illuminating Company~~

	~~Report of Independent Registered Public Accounting Firm~~	8
	~~Consolidated Statements of Income~~	9
	~~Consolidated Balance Sheets~~	10
	~~Consolidated Statements of Capitalization~~	11
	~~Consolidated Statements of Common Stockholder’s Equity~~	12
	~~Consolidated Statements of Cash Flows~~	13

~~The Toledo Edison Company~~

	~~Report of Independent Registered Public Accounting Firm~~	14
	~~Consolidated Statements of Income~~	15
	~~Consolidated Balance Sheets~~	16
	~~Consolidated Statements of Capitalization~~	17
	~~Consolidated Statements of Common Stockholder’s Equity~~	18
	~~Consolidated Statements of Cash Flows~~	19

~~Pennsylvania Electric Company~~

	~~Report of Independent Registered Public Accounting Firm~~	20
	~~Consolidated Statements of Income~~	21
	~~Consolidated Balance Sheets~~	22
	~~Consolidated Statements of Capitalization~~	23
	~~Consolidated Statements of Common Stockholder’s Equity~~	24
	~~Consolidated Statements of Cash Flows~~	25

~~Combined Notes to Consolidated Financial Statements~~		~~26-86~~

~~Item 9A(T). Controls and Procedures.~~		87

~~Item 15. Exhibits.~~		88

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
Centerior	Centerior Energy Corporation, former parent of CEI and TE, which merged with OE to form FirstEnergy on November 8, 1997
~~Companies~~	~~OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec~~
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial and other corporate support services
FEV	FirstEnergy Ventures Corp., invests in certain unregulated enterprises and business ventures
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., a public utility holding company
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition Funding	JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds
JCP&L Transition Funding II	JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition bonds
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MYR	MYR Group, Inc., a utility infrastructure construction service company
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies	CEI, OE and TE
~~Pennsylvania Companies~~	~~Met-Ed, Penelec and Penn~~
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
~~PNBV~~Pennsylvania Companies	~~PNBV Capital Trust, a special purpose entity created by~~ Met-Ed, Penelec and Penn
Shelf Registrants	OE, ~~in 1996~~CEI, TE, JCP&L, Met-Ed and Penelec
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak	A joint venture between FirstEnergy Ventures Corp. and Boich Companies, that owns mining and coal transportation operations near Roundup, Montana, formerly known as Bull Mountain
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
Utilities	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
Waverly	The Waverly Power and Light Company, a wholly owned subsidiary of Penelec

The following abbreviations and acronyms are used to identify frequently used terms in this report:

ACO	Administrative Consent Order
AEP	American Electric Power Company, Inc.
ALJ	Administrative Law Judge
~~AOCI~~AMP-Ohio	~~Accumulated Other Comprehensive Income~~
~~AOCL~~	~~Accumulated Other Comprehensive Loss~~
~~APIC~~	~~Additional Paid-In Capital~~American Municipal Power - Ohio
AQC	Air Quality Control
~~ARB~~	~~Accounting Research Bulletin~~
~~ARO~~	~~Asset Retirement Obligation~~
BGS	Basic Generation Service
~~BPJ~~	~~Best Professional Judgment~~
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAVR	Clean Air Visibility Rule
~~CAT~~	~~Commercial Activity Tax~~
CBP	Competitive Bid Process
CO2	Carbon Dioxide
CTC	Competitive Transition Charge
DFI	Demand for Information
DOE	United States Department of Energy
DOJ	United States Department of Justice
DRA	Division of Ratepayer Advocate
ECAR	East Central Area Reliability Coordination Agreement
~~ECO~~	~~Electro-Catalytic Oxidation~~

EIS	Energy Independence Strategy
~~EITF~~	~~Emerging Issues Task Force~~
~~EITF 06-11~~	~~EITF 06-11, “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”~~
EMP	Energy Master Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
EPRI	Electric Power Research Institute
ERO	Electric Reliability Organization
ESP	Electric Security Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
~~FIN~~	~~FASB Interpretation~~
~~FIN 39-1~~	~~FIN 39-1, “Amendment of FASB Interpretation No. 39”~~
~~FIN 46R~~	~~FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"~~
~~FIN 47~~	~~FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"~~
~~FIN 48~~	~~FIN 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109”~~

FMB	First Mortgage ~~Bonds~~Bond
~~FSP~~FPA	~~FASB Staff Position~~
~~FSP SFAS 115-1~~ ~~and SFAS 124-1~~	~~FSP SFAS 115-1 and SFAS 124-1, “The Meaning of Other-Than-Temporary Impairment and its~~ ~~Application to Certain Investments”~~
~~FTR~~	~~Financial Transmission Rights~~
~~GAAP~~	~~Accounting Principles Generally Accepted in the United States~~Federal Power Act
GHG	Greenhouse Gases
~~HVAC~~	~~Heating, Ventilation and Air-conditioning~~
IRS	Internal Revenue Service
ISO	Independent System Operator
kvkV	~~Kilovolt~~Kilovolts
KWH	Kilowatt-hours
~~LOC~~LED	~~Letter of Credit~~Light-emitting Diode
~~MEIUG~~MEW	~~Met-Ed Industrial Users Group~~Mission Energy Westside, Inc.
MISO	Midwest Independent Transmission System Operator, Inc.
~~MTC~~Moody’s	Moody’s Investors Service, Inc.
MRO	Market ~~Transition Charge~~Rate Offer
MW	Megawatts
MWH	Megawatt-hour
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
~~NOPR~~	~~Notice of Proposed Rulemaking~~
NOV	Notice of Violation
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
OCA	Office of Consumer Advocate
~~OCI~~OSBA	~~Other Comprehensive Income~~Office of Small Business Advocate
~~OPEB~~OVEC	~~Other Post-Employment Benefits~~
~~PICA~~	~~Penelec Industrial Customer Alliance~~Ohio Valley Electric Corporation
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort; an electric utility’s obligation to provide generation service to customers whose alternative supplier fails to deliver service
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PSA	Power Supply Agreement
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
~~REC~~	~~Renewable Energy Certificate~~
RECB	Regional Expansion Criteria and Benefits
RFP	Request for Proposal
~~ROP~~	~~Reactor Oversight Process~~
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization

S&P	Standard & Poor’s Ratings Service
SBC	Societal Benefits Charge
~~SCR~~	~~Selective Catalytic Reduction~~
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
~~SERP~~	~~Supplemental Executive Retirement Plan~~
SFAS	Statement of Financial Accounting Standards
~~SFAS 13~~	~~SFAS No. 13, “Accounting for Leases”~~
SFAS 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 101	SFAS No. 101, "Accounting for Discontinuation of Application of SFAS 71"
~~SFAS 107~~	~~SFAS No. 107, “Disclosure about Fair Value of Financial Instruments”~~
~~SFAS 109~~	~~SFAS No. 109, “Accounting for Income Taxes”~~
~~SFAS 115~~	~~SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities"~~
~~SFAS 123(R)~~	~~SFAS No. 123(R), "Share-Based Payment"~~
~~SFAS 133~~	~~SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”~~
~~SFAS 141(R)~~	~~SFAS No. 141(R), “Business Combinations”~~
~~SFAS 142~~	~~SFAS No. 142, "Goodwill and Other Intangible Assets"~~
~~SFAS 143~~	~~SFAS No. 143, "Accounting for Asset Retirement Obligations"~~
~~SFAS 144~~	~~SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"~~
~~SFAS 157~~	~~SFAS No. 157, “Fair Value Measurements”~~
~~SFAS 158~~	~~SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement~~ ~~Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)”~~
~~SFAS 159~~	~~SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an~~ ~~Amendment of FASB Statement No. 115”~~
~~SFAS 160~~	~~SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”~~
SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
~~TBC~~	~~Transition Bond Charge~~
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
~~VIE~~TSC	~~Variable Interest Entity~~Transmission Service Charge

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME



For the Years Ended December 31,	2007			2006			2005
	(In thousands)
REVENUES (Note 3):
Electric sales	$	2,375,306		$	2,312,956		$	2,861,043
Excise and gross receipts tax collections		116,223			114,500			114,510
Total revenues		2,491,529			2,427,456			2,975,553

EXPENSES (Note 3):
Fuel		11,691			11,047			53,113
Purchased power		1,359,783			1,275,975			939,193
Nuclear operating costs		174,696			186,377			337,901
Other operating costs		381,339			378,717			404,763
Provision for depreciation		77,405			72,982			108,583
Amortization of regulatory assets		191,885			190,245			457,205
Deferral of new regulatory assets		(177,633	)		(159,465	)		(151,032	)
General taxes		181,104			180,446			193,284
Total expenses		2,200,270			2,136,324			2,343,010

OPERATING INCOME		291,259			291,132			632,543

OTHER INCOME (EXPENSE) (Note 3):
Investment income		85,848			130,853			99,269
Miscellaneous income (expense)		4,409			1,751			(25,190	)
Interest expense		(83,343	)		(90,355	)		(75,388	)
Capitalized interest		266			2,198			10,849
Subsidiary's preferred stock dividend requirements		-			(597	)		(1,689	)
Total other income		7,180			43,850			7,851

INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		298,439			334,982			640,394

INCOME TAXES		101,273			123,343			309,996

INCOME BEFORE CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE		197,166			211,639			330,398

Cumulative effect of a change in accounting principle
(net of income tax benefit of $9,223,000) (Note 2(G))		-			-			(16,343	)

NET INCOME		197,166			211,639			314,055

PREFERRED STOCK DIVIDEND REQUIREMENTS
AND REDEMPTION PREMIUM		-			4,552			2,635

EARNINGS ON COMMON STOCK	$	197,166		$	207,087		$	311,420


The accompanying Combined Notes to Consolidated Financial Statements as they relate to Ohio Edison Company
are an integral part of these statements.

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

As of December 31,	2007		2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	732	$	712
Receivables-
Customers (less accumulated provisions of $8,032,000 and $15,033,000, respectively,
for uncollectible accounts)		248,990		234,781
Associated companies		185,437		141,084
Other (less accumulated provisions of $5,639,000 and $1,985,000, respectively,
for uncollectible accounts)		12,395		13,496
Notes receivable from associated companies		595,859		458,647
Prepayments and other		10,341		13,606
		1,053,754		862,326
UTILITY PLANT:
In service		2,769,880		2,632,207
Less - Accumulated provision for depreciation		1,090,862		1,021,918
		1,679,018		1,610,289
Construction work in progress		50,061		42,016
		1,729,079		1,652,305
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		258,870		1,219,325
Investment in lease obligation bonds (Note 6)		253,894		291,393
Nuclear plant decommissioning trusts		127,252		118,209
Other		36,037		38,160
		676,053		1,667,087
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		737,326		741,564
Pension assets		228,518		68,420
Property taxes		65,520		60,080
Unamortized sale and leaseback costs		45,133		50,136
Other		48,075		18,696
		1,124,572		938,896
	$	4,583,458	$	5,120,614
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	333,224	$	159,852
Short-term borrowings-
Associated companies		50,692		113,987
Other		2,609		3,097
Accounts payable-
Associated companies		174,088		115,252
Other		19,881		13,068
Accrued taxes		89,571		187,306
Accrued interest		22,378		24,712
Other		65,163		64,519
		757,606		681,793
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		1,576,175		1,972,385
Long-term debt and other long-term obligations		840,591		1,118,576
		2,416,766		3,090,961
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		781,012		674,288
Accumulated deferred investment tax credits		16,964		20,532
Asset retirement obligations		93,571		88,223
Retirement benefits		178,343		167,379
Deferred revenues - electric service programs		46,849		86,710
Other		292,347		310,728
		1,409,086		1,347,860
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	4,583,458	$	5,120,614


The accompanying Combined Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of
these balance sheets.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

As of December 31,	2007			2006
	(In thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, 175,000,000 shares authorized,
60 and 80 shares outstanding, respectively	$	1,220,512		$	1,708,441
Accumulated other comprehensive income (Note 2(F))		48,386			3,208
Retained earnings (Note 10(A))		307,277			260,736
Total		1,576,175			1,972,385

LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 10(C)):
Ohio Edison Company-
Secured notes:
5.375% due 2028		13,522			13,522
* 3.780% due 2029		-			100,000
* 3.750% due 2029		-			6,450
7.008% weighted average interest rate due 2007-2010		3,900			8,253
Total		17,422			128,225

Unsecured notes:
4.000% due 2008		175,000			175,000
* 3.400% due 2014		50,000			50,000
5.450% due 2015		150,000			150,000
6.400% due 2016		250,000			250,000
* 3.850% due 2018		33,000			33,000
* 3.800% due 2018		23,000			23,000
* 3.750% due 2023		50,000			50,000
6.875% due 2036		350,000			350,000
Total		1,081,000			1,081,000

Pennsylvania Power Company-
First mortgage bonds:
9.740% due 2007-2019		11,721			12,695
7.625% due 2023		6,500			6,500
Total		18,221			19,195

Secured notes:
5.400% due 2013		1,000			1,000
5.375% due 2028		1,734			1,734
Total		2,734			2,734

Unsecured notes:
5.390% due 2010 to associated company		62,900			62,900
Total		62,900			62,900

Capital lease obligations (Note 6)		329			362
Net unamortized discount on debt		(8,791	)		(15,988	)
Long-term debt due within one year		(333,224	)		(159,852	)
Total long-term debt and other long-term obligations		840,591			1,118,576
TOTAL CAPITALIZATION	$	2,416,766		$	3,090,961

* Denotes variable rate issue with applicable year-end interest rate shown.

The accompanying Combined Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an
integral part of these statements.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

										Accumulated
				Common Stock						Other
	Comprehensive			Number			Carrying			Comprehensive			Retained
	Income			of Shares			Value			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2005					100		$	2,098,729		$	(47,118	)	$	442,198
Net income	$	314,055												314,055
Minimum liability for unfunded retirement
benefits, net of $49,027,000 of income taxes		69,463									69,463
Unrealized loss on investments, net of
$13,068,000 of income tax benefits		(18,251	)								(18,251	)
Comprehensive income	$	365,267
Affiliated company asset transfers								198,147						(106,774	)
Restricted stock units								32
Preferred stock redemption adjustment								345
Cash dividends on preferred stock														(2,635	)
Cash dividends on common stock														(446,000	)
Balance, December 31, 2005					100			2,297,253			4,094			200,844
Net income	$	211,639												211,639
Unrealized gain on investments, net of
$4,455,000 of income taxes		7,954									7,954
Comprehensive income	$	219,593
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $22,287,000 of income tax benefits (Note 4)											(8,840	)
Affiliated company asset transfers								(87,893	)
Restricted stock units								58
Stock based compensation								82
Repurchase of common stock					(20	)		(500,000	)
Preferred stock redemption adjustments								(1,059	)					604
Preferred stock redemption premiums														(2,928	)
Cash dividends on preferred stock														(1,423	)
Cash dividends on common stock														(148,000	)
Balance, December 31, 2006					80			1,708,441			3,208			260,736
Net income	$	197,166												197,166
Unrealized gain on investments, net of
$2,784,000 of income taxes		3,874									3,874
Pension and other postretirement benefits, net
of $37,820,000 of income taxes (Note 4)		41,304									41,304
Comprehensive income	$	242,344
Restricted stock units								129
Stock based compensation								17
Repurchase of common stock					(20	)		(500,000	)
Consolidated tax benefit allocation								11,925
FIN 48 cumulative effect adjustment														(625	)
Cash dividends on common stock														(150,000	)
Balance, December 31, 2007					60		$	1,220,512		$	48,386		$	307,277

The accompanying Combined Notes to Consolidated Financial Statements as the relate to Ohio Edison Company are an integral
part of these statements.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Restated
For the Years Ended December 31,	2007			2006			2005
				(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	197,166		$	211,639		$	314,055
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		77,405			72,982			108,583
Amortization of regulatory assets		191,885			190,245			457,205
Deferral of new regulatory assets		(177,633	)		(159,465	)		(151,032	)
Nuclear fuel and lease amortization		33			735			45,769
Amortization of lease costs		(7,425	)		(7,928	)		(6,365	)
Deferred income taxes and investment tax credits, net		423			(68,259	)		(29,750	)
Accrued compensation and retirement benefits		(46,313	)		5,004			14,506
Cumulative effect of a change in accounting principle		-			-			16,343
Pension trust contributions		(20,261	)		-			(106,760	)
Decrease (increase) in operating assets-
Receivables		(57,461	)		103,925			84,688
Materials and supplies		-			-			(3,367	)
Prepayments and other current assets		3,265			1,275			(1,778	)
Increase (decrease) in operating liabilities-
Accounts payable		15,649			(53,798	)		45,149
Accrued taxes		(81,079	)		23,436			10,470
Accrued interest		(2,334	)		16,379			(3,659	)
Electric service prepayment programs		(39,861	)		(34,983	)		121,692
Other		6,096			5,882			(464	)
Net cash provided from operating activities		59,555			307,069			915,285

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			592,180			146,450
Short-term borrowings, net		-			-			26,404
Redemptions and Repayments-
Common stock		(500,000	)		(500,000	)		-
Preferred stock		-			(78,480	)		(37,750	)
Long-term debt		(112,497	)		(613,002	)		(414,020	)
Short-term borrowings, net		(114,475	)		(186,511	)		-
Dividend Payments-
Common stock		(100,000	)		(148,000	)		(446,000	)
Preferred stock		-			(1,423	)		(2,635	)
Net cash used for financing activities		(826,972	)		(935,236	)		(727,551	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(145,311	)		(123,210	)		(266,823	)
Sales of investment securities held in trusts		37,736			39,226			283,816
Purchases of investment securities held in trusts		(43,758	)		(41,300	)		(315,356	)
Loan repayments from (loans to) associated companies, net		(79,115	)		78,101			(35,553	)
Collection of principal on long-term notes receivable		960,327			553,734			199,848
Cash investments		37,499			112,584			(49,270	)
Other		59			8,815			(4,697	)
Net cash provided from (used for) investing activities		767,437			627,950			(188,035	)

Net increase (decrease) in cash and cash equivalents		20			(217	)		(301	)
Cash and cash equivalents at beginning of year		712			929			1,230
Cash and cash equivalents at end of year	$	732		$	712		$	929

SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	80,958		$	57,243		$	67,239
Income taxes	$	133,170		$	156,610		$	285,819

The accompanying Combined Notes to Consolidated Financial Statements as the relate to Ohio Edison Company are an integral part of
these statements.

	Page
Part I
Item 1. Business
The Company	1-2
Utility Regulation	2-11
Regulatory Accounting	3
Reliability Initiatives	3-4
PUCO Rate Matters	4-5
PPUC Rate Matters	6-7
NJBPU Rate Matters	7-8
FERC Rate Matters	8-11
Capital Requirements	11-13
Nuclear Operating Licenses	13-14
Nuclear Regulation	14
Nuclear Insurance	14-15
Environmental Matters	15-19
Fuel Supply	19-20
System Demand	20
Supply Plan	20
Regional Reliability	21
Competition	21
Research and Development	21
Executive Officers	22
Employees	23
FirstEnergy Web Site	23

Item 1A. Risk Factors	23-36

Item 1B. Unresolved Staff Comments	36

Item 2. Properties	36-38

Item 3. Legal Proceedings	38

Item 4. Submission of Matters to a Vote of Security Holders	38

Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38-39

Item 6. Selected Financial Data	39

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	39

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	39

Item 8. Financial Statements and Supplementary Data	39

Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	39

Item 9A. Controls and Procedures	39-40

Item 9A(T). Controls and Procedures	40

Item 9B. Other Information	40

Part III
Item 10. Directors, Executive Officers and Corporate Governance	41

Item 11. Executive Compensation	41

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	41

Item 13. Certain Relationships and Related Transactions, and Director Independence	41

Item 14. Principal Accounting Fees and Services	41

Part IV
Item 15. Exhibits, Financial Statement Schedules	42-88

OE

	Year Ended
	December 31, 2007
	As Previously			As
	Reported			Restated
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	197,166		$	197,166
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		77,405			77,405
Amortization of regulatory assets		191,885			191,885
Deferral of new regulatory assets		(177,633	)		(177,633	)
Nuclear fuel and lease amortization		33			33
Amortization of lease costs		(7,425	)		(7,425	)
Deferred income taxes and investment tax credits, net		423			423
Accrued compensation and retirement benefits		(46,313	)		(46,313	)
Pension trust contributions		(20,261	)		(20,261	)
Decrease (increase) in operating assets-
Receivables		(57,461	)		(57,461	)
Prepayments and other current assets		3,265			3,265
Increase (decrease) in operating liabilities-
Accounts payable		65,649			15,649
Accrued taxes		(81,079	)		(81,079	)
Accrued interest		(2,334	)		(2,334	)
Electric service prepayment programs		(39,861	)		(39,861	)
Other		6,096			6,096
Net cash provided from operating activities		109,555			59,555

CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Common stock		(500,000	)		(500,000	)
Long-term debt		(112,497	)		(112,497	)
Short-term borrowings, net		(114,475	)		(114,475	)
Dividend Payments-
Common stock		(150,000	)		(100,000	)
Net cash used for financing activities		(876,972	)		(826,972	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(145,311	)		(145,311	)
Sales of investment securities held in trusts		37,736			37,736
Purchases of investment securities held in trusts		(43,758	)		(43,758	)
Loans to associated companies, net		(79,115	)		(79,115	)
Collection of principal on long-term notes receivable		960,327			960,327
Cash investments		37,499			37,499
Other		59			59
Net cash provided from investing activities		767,437			767,437

Net increase in cash and cash equivalents	$	20		$	20

Regulatory Assets *	OE			CEI			TE			JCP&L			Met-Ed
December 31, 2007	(In millions)
Regulatory transition costs	$	197		$	227		$	71		$	1,630		$	237
Customer shopping incentives		91			393			32			-			-
Customer receivables (payables) for future income taxes		101			18			(1	)		51			126
Loss (Gain) on reacquired debt		23			2			(3	)		25			10
Employee postretirement benefit costs		-			8			4			17			10
Nuclear decommissioning, decontamination
and spent fuel disposal costs		-			-			-			-			(115	)
Asset removal costs		(6	)		(18	)		(11	)		(148	)		-
Property losses and unrecovered plant costs		-			-			-			9			-
MISO/PJM transmission costs		56			34			24			-			226
Fuel costs RCP		111			77			33			-			-
Distribution costs RCP		148			122			51			-			-
Other		16			8			4			12			1
Total	$	737		$	871		$	204		$	1,596		$	495

December 31, 2006
Regulatory transition costs	$	280		$	360		$	134		$	2,207		$	285
Customer shopping incentives		174			368			61			-			-
Customer receivables (payables) for future income taxes		81			3			(4	)		22			116
Societal benefits charge		-			-			-			11			-
Loss (Gain) on reacquired debt		24			-			(3	)		11			11
Employee postretirement benefit costs		-			10			5			20			12
Nuclear decommissioning, decontamination
and spent fuel disposal costs		-			-			-			(1	)		(144	)
Asset removal costs		(2	)		(12	)		(5	)		(148	)		-
Property losses and unrecovered plant costs		-			-			-			19			-
MISO/PJM transmission costs		44			26			16			-			127
Fuel costs RCP		57			39			17			-			-
Distribution costs RCP		74			57			24			-			-
Other		9			4			3			11			2
Total	$	741		$	855		$	248		$	2,152		$	409

Amortization
Period	OE		CEI		TE
	(In millions)
2008	$	207	$	126	$	113
2009		-		212		-
2010		-		273		-
Total Amortization	$	207	$	611	$	113

Customer Receivables	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
December 31, 2007	(In millions)
Billed	$	107	$	143	$	144	$	-	$	162	$	80	$	75
Unbilled		27		106		107		-		159		63		62
Total	$	134	$	249	$	251	$	-	$	321	$	143	$	137
December 31, 2006
Billed	$	104	$	127	$	137	$	1	$	128	$	70	$	69
Unbilled		26		108		108		-		126		57		58
Total	$	130	$	235	$	245	$	1	$	254	$	127	$	127

	Annual Composite
	Depreciation Rate
	2007			2006			2005
OE		2.9	%		2.8	%		2.1	%
CEI		3.6			3.2			2.9
TE		3.9			3.8			3.1
Penn		2.3			2.6			2.4
JCP&L		2.1			2.1			2.2
Met-Ed		2.3			2.3			2.4
Penelec		2.3			2.3			2.6
FGCO		4.0			4.1			N/A
NGC		2.8			2.7			N/A

Goodwill	FES			CEI			TE			JCP&L			Met-Ed			Penelec
	(In millions)
Balance as of January 1, 2005	$	26		$	1,694		$	505		$	1,998		$	870		$	888
Non-core sset sales		(2	)		-			-			-			-			-
Adjustments related to GPU acquisition											(12	)		(6	)		(6	)
Adjustments related to Centerior acquisition					(5	)		(4	)
Balance as of December 31, 2005		24			1,689			501			1,986			864			882
Impairment charges														(355	)
Adjustments related to Centerior acquisition
Adjustments related to GPU acquisition											(24	)		(13	)		(21	)
Balance as of December 31, 2006		24			1,689			501			1,962			496			861
Adjustments related to GPU acquisition											(136	)		(72	)		(83	)
Balance as of December 31, 2007	$	24		$	1,689		$	501		$	1,826		$	424		$	778

Affiliated Company Transactions - 2007	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Revenues:
Electric sales to affiliates	$	2,901	$	73	$	92	$	167	$	-	$	-	$	-
Ground lease with ATSI		-		12		7		2		-		-		-

Expenses:
Purchased power from affiliates		234		1,261		770		392		-		290		285
Support services		560		146		70		55		100		54		58

Investment Income:
Interest income from affiliates		-		30		17		18		1		1		1
Interest income from FirstEnergy		28		29		2		-		-		-		-

Interest Expense:
Interest expense to affiliates		31		1		1		-		1		1		1
Interest expense to FirstEnergy		34		-		1		10		11		10		11

Affiliated Company Transactions - 2006	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Revenues:
Electric sales to affiliates	$	2,609	$	80	$	95	$	170	$	14	$	-	$	-
Ground lease with ATSI		-		12		7		2		-		-		-

Expenses:
Purchased power from affiliates		257		1,264		727		363		25		178		154
Support services		602		143		63		63		93		51		55

Investment Income:
Interest income from affiliates		-		75		58		32		1		1		1
Interest income from FirstEnergy		12		25		-		-		-		-		-

Interest Expense:
Interest expense to affiliates		109		-		-		-		-		-		-
Interest expense to FirstEnergy		53		-		7		7		11		5		11

Affiliated Company Transactions - 2005	FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Revenues:
Electric sales to affiliates	$	2,425	$	355	$	362	$	300	$	33	$	-	$	-
Generating units rent from FES		-		146		49		12		-		-		-
Ground lease with ATSI		-		12		7		2		-		-		-

Expenses:
Purchased power from affiliates		308		938		557		295		78		348		321
Support services		64		314		257		171		94		45		51

Investment Income:
Interest income from affiliates		-		25		7		22		-		-		-
Interest income from FirstEnergy		-		22		-		-		-		-		-

Interest Expense:
Interest expense to affiliates		129		-		-		-		-		-		-
Interest expense to FirstEnergy		55		1		-		11		4		2		4

Obligations and Funded Status	Pension Benefits						Other Benefits
As of December 31	2007			2006			2007			2006
	(In millions)
Change in benefit obligation
Benefit obligation as of January 1	$	5,031		$	4,911		$	1,201		$	1,884
Service cost		88			87			21			34
Interest cost		294			276			69			105
Plan participants' contributions		-			-			23			20
Plan amendments		-			-			-			(620	)
Medicare retiree drug subsidy		-			-			-			6
Actuarial (gain) loss		(381	)		38			(30	)		(119	)
Benefits paid		(282	)		(281	)		(102	)		(109	)
Benefit obligation as of December 31	$	4,750		$	5,031		$	1,182		$	1,201

Change in fair value of plan assets
Fair value of plan assets as of January 1	$	4,818		$	4,525		$	607		$	573
Actual return on plan assets		438			567			43			69
Company contribution		311			7			47			54
Plan participants' contribution		-			-			23			20
Benefits paid		(282	)		(281	)		(102	)		(109	)
Fair value of plan assets as of December 31	$	5,285		$	4,818		$	618		$	607

Qualified plan	$	700		$	(43	)
Non qualified plans		(165	)		(170	)
Funded status	$	535		$	(213	)	$	(564	)	$	(594	)

Accumulated benefit obligation	$	4,397		$	4,585

Amounts Recognized in the Statement of
Financial Position
Noncurrent assets	$	700		$	-		$	-		$	-
Current liabilities		(7	)		(7	)		-			-
Noncurrent liabilities		(158	)		(206	)		(564	)		(594	)
Net asset (liability) as of December 31	$	535		$	(213	))	$	(564	)	$	(594	)

Amounts Recognized in
Accumulated Other Comprehensive Income
Prior service cost (credit)	$	83		$	97		$	(1,041	)	$	(1,190	)
Actuarial loss		623			1,039			635			702
Net amount recognized	$	706		$	1,136		$	(406	)	$	(488	)

Assumptions Used to Determine
Benefit Obligations As of December 31
Discount rate		6.50	%		6.00	%		6.50	%		6.00	%
Rate of compensation increase		5.20	%		3.50	%

Allocation of Plan Assets
As of December 31
Asset Category
Equity securities		61	%		64	%		69	%		72	%
Debt securities		30			29			27			26
Real estate		7			5			2			1
Private equities		1			1			-			-
Cash		1			1			2			1
Total		100	%		100	%		100	%		100	%

	Pension Benefits					Other Benefits
Net Pension and OPEB Asset (Liability)	2007		2006			2007			2006
	(In millions)
FES	$	42	$	(157	)	$	(102	)	$	(81	)
OE		229		68			(178	)		(167	)
CEI		62		(13	)		(93	)		(110	)
TE		29		(3	)		(63	)		(74	)
JCP&L		93		15			8			(8	)
Met-Ed		51		7			(8	)		(19	)
Penelec		66		11			(40	)		(49	)

Estimated Items to be Amortized in 2008
Net Periodic Pension Cost from	Pension		Other
Accumulated Other Comprehensive Income	Benefits		Benefits
	(In millions)
Prior service cost (credit)	$	13	$	(149	)
Actuarial loss	$	8	$	47

		Pension Benefits									Other Benefits
Components of Net Periodic Benefit Costs			2007			2006			2005			2007			2006			2005
	(In millions)
Service cost		$	88		$	87		$	80		$	21		$	34		$	40
Interest cost			294			276			262			69			105			111
Expected return on plan assets			(449	)		(396	)		(345	)		(50	)		(46	)		(45	)
Amortization of prior service cost			13			13			10			(149	)		(76	)		(45	)
Recognized net actuarial loss			45			62			39			45			56			40
Net periodic cost		$	(9	)	$	42		$	46		$	(64	)	$	73		$	101

Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost		Pension Benefits									Other Benefits
for Years Ended December 31		2007			2006			2005			2007			2006			2005
Discount rate			6.00	%		5.75	%		6.00	%		6.00	%		5.75	%		6.00	%
Expected long-term return on plan assets			9.00	%		9.00	%		9.00	%		9.00	%		9.00	%		9.00	%
Rate of compensation increase			3.50	%		3.50	%		3.50	%

	Pension Benefits									Other Benefits
Net Periodic Pension and OPEB Costs	2007			2006			2005			2007			2006		2005
	(In millions)
FES	$	21		$	40		$	33		$	(10	)	$	14	$	23
OE		(16	)		(6	)		0			(11	)		17		28
CEI		1			4			1			4			11		15
TE		-			1			1			5			8		9
JCP&L		(9	)		(5	)		(1	)		(16	)		2		7
Met-Ed		(7	)		(7	)		(4	)		(10	)		3		1
Penelec		(10	)		(5	)		(5	)		(13	)		7		8

Assumed Health Care Cost Trend Rates
As of December 31	2007			2006
Health care cost trend rate assumed for next
year (pre/post-Medicare)		9-11	%		9-11	%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)		5	%		5	%
Year that the rate reaches the ultimate trend
rate (pre/post-Medicare)		2015-2017			2011-2013

	1-Percentage-		1-Percentage-
	Point Increase		Point Decrease
	(In millions)
Effect on total of service and interest cost	$	5	$	(4	)
Effect on accumulated postretirement benefit obligation	$	48	$	(42	)