OHIO EDISON CO (Form: 10-K, Received: 02/28/2007 06:00:13)

Reconciliation of Basic and Diluted
Earnings per Share of Common Stock			2006			2005			2004
			*(In millions, except per share amounts)*

Income from continuing operations			$	1,258		$	879		$	907
Less: Redemption premium on subsidiary preferred stock				(9	)		-			-
Income from continuing operations available to common shareholders				1,249			879			907
Discontinued operations				(4	)		12			(29	)
Income before cumulative effect of a change in accounting principle				1,245			891			878
Cumulative effect of a change in accounting principle				-			(30	)		-
Net income available for common shareholders			$	1,245		$	861		$	878

Average shares of common stock outstanding - Basic				324			328			327
Assumed exercise of dilutive stock options and awards				3			2			2
Average shares of common stock outstanding - Dilutive				327			330			329

Earnings per share:
	Basic earnings per share:
		Earnings from continuing operations	$	3.85		$	2.68		$	2.77
		Discontinued operations		(0.01	)		0.03			(0.09	)
		Cumulative effect of change in accounting principle		-			(0.09	)		-
		Net earnings per basic share	$	3.84		$	2.62		$	2.68

	Diluted earnings per share:
		Earnings from continuing operations	$	3.82		$	2.67		$	2.76
		Discontinued operations		(0.01	)		0.03			(0.09	)
		Cumulative effect of change in accounting principle		-			(0.09	)		-
		Net earnings per diluted share	$	3.81		$	2.61		$	2.67

(F)

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. FirstEnergy's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.

FirstEnergy provides 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 FirstEnergy’s subsidiaries’ electric plant in 2006, 2005 and 2004 are shown in the following table:

	Annual Composite
	Depreciation Rate
	2006			2005			2004
OE		2.8	%		2.1	%		2.3	%
CEI		3.2			2.9			2.8
TE		3.8			3.1			2.8
Penn		2.6			2.4			2.2
JCP&L		2.1			2.2			2.1
Met-Ed		2.3			2.4			2.4
Penelec		2.3			2.6			2.5
FGCO		4.1			N/A			N/A
NGC		2.7			N/A			N/A

Jointly-Owned Generating Stations

JCP&L holds a 50% ownership interest in Yards Creek Pumped Storage Facility - its net book value was approximately $20 million as of December 31, 2006. All other generating units are owned and/or leased by FGCO, NGC and the Companies.

Asset Retirement Obligations

FirstEnergy recognizes a liability 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 12, "Asset Retirement Obligations."

Nuclear Fuel

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.

(G)

STOCK-BASED COMPENSATION-

FirstEnergy applied the recognition and measurement principles of SFAS 123(R) and related interpretations as of January 1, 2006, which required the expensing of stock-based compensation. All share-based compensation costs are measured at the grant date based on the fair value of the award, and is recognized as an expense over the employee’s service period. Those awards that have been classified as liabilities are re-measured each reporting period at the current fair value. FirstEnergy adopted SFAS 123(R) using the modified prospective method under which compensation expense recognized in the year ended December 31, 2006 includes the expense for all share-based payments granted prior to, but not yet vested, as of January 1, 2006.

(H) ASSET IMPAIRMENTS-

Long-Lived Assets

FirstEnergy evaluates the carrying value of its 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, FirstEnergy evaluates its goodwill for impairment at least annually and makes 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, FirstEnergy recognizes a loss - calculated as the difference between the implied fair value of a reporting unit’s goodwill and the carrying value of the goodwill. FirstEnergy's 2006 annual review was completed in the third quarter of 2006 with no impairment indicated. As discussed in Note 10 to the consolidated financial statements, the PPUC issued its order on January 11, 2007 related to the comprehensive rate filing made by Met-Ed and Penelec on April 10, 2006. Prior to issuing the order, the PPUC conducted an informal, nonbinding polling of Commissioners at its public meeting on December 21, 2006 that indicated that the rate increase ultimately granted could be substantially lower than the amounts requested. As a result of the polling, FirstEnergy determined that an interim review of goodwill for its Regulated Services reporting unit would be required. No impairment was indicated as a result of that review.

FirstEnergy's 2005 annual review was completed in the third quarter of 2005 with no impairment indicated. In December 2005, MYR qualified as an asset held for sale in accordance with SFAS 144. SFAS 142 requires the goodwill of a reporting unit to be tested for impairment if there is a more-likely-than-not expectation that the reporting unit or a significant asset group within the reporting unit will be sold. As a result, in the fourth quarter of 2005, the goodwill of MYR was retested for impairment. Based on market valuations that were not available prior to the fourth quarter of 2005, it was determined that the carrying value of MYR exceeded the fair value, resulting in a non-cash goodwill impairment charge of $9 million in the fourth quarter of 2005, with no corresponding income tax benefit.

FirstEnergy's 2004 annual review was completed in the third quarter of 2004 with no impairment indicated. In December 2004, the FSG subsidiaries qualified as an asset held for sale in accordance with SFAS 144. As required by SFAS 142, the goodwill of FSG was tested for impairment, resulting in a non-cash charge of $36 million in the fourth quarter of 2004. Of that amount, $10 million was reported as an operating expense and $26 million was included in the results from discontinued operations. FSG's fair value was estimated using current market valuations.

The forecasts used in FirstEnergy's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on FirstEnergy's future evaluations of goodwill. FirstEnergy's goodwill primarily relates to its regulated services segment. In the year ended December 31, 2006, FirstEnergy adjusted goodwill related to the divestiture of a non-core asset (MYR), a successful tax claim relating to the former Centerior companies, and adjustments to the former GPU companies due to the realization of tax benefits that had been reserved in purchase accounting . The impairment analysis includes a significant source of cash representing the Companies' recovery of transition costs as described in Note 10. FirstEnergy estimates that completion of transition cost recovery will not result in an impairment of goodwill relating to its regulated business segment.

A summary of the changes in FirstEnergy's goodwill for the three years ended December 31, 2006 is shown below by segment (see Note 16 - Segment Information):

				Power
				Supply
	Regulated			Management		Facilities
	Services			Services		Services			Other			Consolidated
						*(In millions)*
Balance as of January 1, 2004	$	5,993		$	24	$	36		$	75		$	6,128
Impairment charges							(36	)					(36	)
Adjustments related to GPU acquisition		(42	)										(42	)
Balance as of December 31, 2004		5,951			24		-			75			6,050
Impairment charges										(9	)		(9	)
Non-core asset sales										(12	)		(12	)
Adjustments related to GPU acquisition		(10	)										(10	)
Adjustments related to Centerior acquisition		(9	)										(9	)
Balance as of December 31, 2005		5,932			24		-			54			6,010
Non-core asset sale										(53	)		(53	)
Adjustments related to Centerior acquisition		(1	)										(1	)
Adjustments related to GPU acquisition		(58	)										(58	)
Balance as of December 31, 2006	$	5,873		$	24	$	-		$	1		$	5,898

Investments

At the end of each reporting period, FirstEnergy evaluates its 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. FirstEnergy first considers its intent and ability to hold the investment until recovery and then considers, 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, FirstEnergy began recognizing in earnings the unrealized losses on available-for-sale securities held in the 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 the Company's investments are disclosed in Note 5(B) and 5(C).

(I) COMPREHENSIVE INCOME-

Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholders' equity, excluding the effect from the adoption of SFAS 158. As of December 31, 2006, AOCL consisted of a net liability for unfunded retirement benefits including the implementation of SFAS 158, net of income tax benefits (see Note 3) of $344 million, unrealized gains on investments in securities available for sale of $143 million and unrealized losses on derivative instrument hedges of $58 million. A summary of the changes in FirstEnergy's AOCL balance for the three years ended December 31, 2006 is shown below:


	2006			2005			2004
	*(In millions)*
AOCL balance as of January 1,	$	(20	)	$	(313	)	$	(353	)

Minimum liability for unfunded retirement benefits		-			503			(11	)
Unrealized gain (loss) on available for sale securities		109			(31	)		46
Unrealized gain on derivative hedges		29			23			29
Other comprehensive income		138			495			64
Income taxes related to OCI		50			202			24
Other comprehensive income, net of tax		88			293			40
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $292 million of income tax benefits		(327	)		-			-
AOCL balance as of December 31,	$	(259	)	$	(20	)	$	(313	)

Other comprehensive loss reclassified to net income in 2006 totaled $4 million (net of income tax benefits of $1 million). Other comprehensive income reclassified to net income in 2005 and 2004 totaled $28 million and $8 million, respectively. These amounts were net of income taxes in 2005 and 2004 of $19 million and $6 million, respectively.

(J) ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS-

In 2006, FirstEnergy sold its remaining FSG subsidiaries (Roth Bros., Hattenbach, Dunbar, Edwards and RPC) for an aggregate net after-tax gain of $2.2 million. Hattenbach, Dunbar, Edwards, and RPC were accounted for as discontinued operations as of December 31, 2006; Roth Bros. did not meet the criteria for that classification as of December 31, 2006.

In December 2005, MYR had qualified as an asset held for sale but did not meet the criteria to be classified as a discontinued operation. As required by SFAS 142, the goodwill of MYR was tested for impairment, resulting in a non-cash charge of $9 million in the fourth quarter of 2005 (see Note 2(H)). The carrying amounts of MYR's assets and liabilities as of December 31, 2005 held for sale were not material and had not been classified as assets held for sale on FirstEnergy's Consolidated Balance Sheet.

In March 2006, FirstEnergy sold 60% of its interest in MYR for an after-tax gain of $0.2 million. In June 2006, as part of the March agreement, FirstEnergy sold an additional 1.67% interest. As a result of the March sale, FirstEnergy deconsolidated MYR in the first quarter of 2006 and accounted for its remaining 38.33% interest under the equity method. In the fourth quarter of 2006, FirstEnergy sold its remaining MYR interest for an after-tax gain of $8.6 million. The income for the period that MYR was accounted for as an equity method investment has not been included in discontinued operations; however, results for all reporting periods prior to the initial sale in March 2006, including the gain on the sale, were reported as discontinued operations. As of December 31, 2006, no assets have been classified as held for sale.

In 2005, three FSG subsidiaries, Elliott-Lewis, Spectrum and Cranston, and MYR's Power Piping Company subsidiary were sold resulting in an after-tax gain of $13 million. As of December 31, 2005, the remaining FSG subsidiaries had qualified as assets held for sale in accordance with SFAS 144 but did not meet the criteria for discontinued operations. The carrying amounts of FSG's assets and liabilities held for sale as of December 31, 2005 were not material and were not classified as assets held for sale on FirstEnergy's Consolidated Balance Sheet.

In December 2004, the FES retail natural gas business qualified as assets held for sale in accordance with SFAS 144. As required by SFAS 142, goodwill associated with the FES natural gas business was tested for impairment as of December 31, 2004 with no impairment indicated. On March 31, 2005, FES completed the sale for an after-tax gain of $5 million.

Revenues associated with discontinued operations were $225 million, $845 million and $1.15 billion in 2006, 2005 and 2004, respectively. The following table summarizes the net income (loss) included in "Discontinued Operations" on the Consolidated Statements of Income for the three years ended December 31, 2006:

	2006			2005			2004
	*(In millions)*
FES natural gas business	$	-		$	5		$	4
FSG subsidiaries		(7	)		8			(29	)
MYR		3			(1	)		(4	)
Income (loss) from discontinued operations	$	(4	)	$	12		$	(29	)

(K)

CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE-

Results in 2005 included an after-tax charge of $30 million recorded upon the adoption of FIN 47 in December 2005. FirstEnergy identified applicable legal obligations as defined under FIN 47 at its active and retired generating units, substation control rooms, service center buildings, line shops and office buildings, identifying asbestos as the primary conditional ARO. The Company recorded a conditional ARO liability of $57 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $16 million (recorded as part of the carrying amount of the related long-lived asset), and accumulated depreciation of $12 million. FirstEnergy charged regulatory liabilities for $5 million upon adoption of FIN 47 for the transition amounts related to establishing the ARO for asbestos removal from substation control rooms and service center buildings for OE, Penn, CEI, TE and JCP&L. The remaining cumulative effect adjustment for unrecognized depreciation and accretion of $48 million was charged to income ($30 million, net of tax), or $0.09 per share of common stock (basic and diluted) for the year ended December 31, 2005 (see Note 12).

(L)

TAXES-

Details of the total taxes for the three years ended December 31, 2006 are shown in the following tables:

GENERAL TAXES	2006			2005			2004
	*(In millions)*
Kilowatt-hour excise*	$	241		$	244		$	236
State gross receipts*		159			151			140
Real and personal property		222			222			208
Social security and unemployment		83			79			76
Other		15			17			18
Total general taxes	$	720		$	713		$	678

* Collected from customers through regulated rates and included in revenue in the Consolidated Statements of Income.

PROVISION FOR INCOME TAXES		2006			2005			2004
		*(In millions)*
Currently payable-
Federal	$	519		$	452		$	289
State		116			142			135
		635			594			424

Deferred, net-
Federal		147			72			245
State		28			110			39
		175			182			284
Investment tax credit amortization		(15	)		(27	)		(27	)
Total provision for income taxes	$	795		$	749		$	681


RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	2,053		$	1,628		$	1,588
Federal income tax expense at statutory rate	$	719		$	569		$	556
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits		(15	)		(27	)		(27	)
State income taxes, net of federal income tax benefit		94			165			111
Penalties		-			14			-
Amortization of tax regulatory assets		2			38			33
Preferred stock dividends		5			5			8
Other, net		(10	)		(15	)		-
Total provision for income taxes	$	795		$	749		$	681


ACCUMULATED DEFERRED INCOME TAXES AS OF
DECEMBER 31:
Property basis differences	$	2,595		$	2,368		$	2,348
Regulatory transition charge		457			537			785
Customer receivables for future income taxes		141			131			103
Deferred customer shopping incentive		219			321			252
Deferred sale and leaseback costs		(86	)		(86	)		(92	)
Nonutility generation costs		(122	)		(177	)		(174	)
Unamortized investment tax credits		(50	)		(54	)		(61	)
Other comprehensive income		(260	)		(18	)		(219	)
Retirement benefits		10			(135	)		(280	)
Lease market valuation liability		(331	)		(361	)		(420	)
Oyster Creek securitization (Note 10(D))		162			173			184
Loss carryforwards		(426	)		(417	)		(463	)
Loss carryforward valuation reserve		415			402			420
Asset retirement obligations		45			65			71
Nuclear decommissioning		(116	)		(105	)		(100	)
All other		87			82			(30	)
Net deferred income tax liability	$	2,740		$	2,726		$	2,324

FirstEnergy records 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 (See Note 9 for Ohio Tax Legislation discussion).

FirstEnergy has certain tax returns that are under review at the audit or appeals level of the IRS and certain state authorities. Reserves have been recorded, and final settlement of these audits is not expected to have an adverse impact on the financial condition or results of operations of FirstEnergy.

FirstEnergy has capital loss carryforwards of approximately $1 billion, most of which expire in 2007. The deferred tax assets associated with these capital loss carryforwards of ($374 million) are fully offset by a valuation allowance as of December 31, 2006, since management is unable to predict whether sufficient capital gains will be generated to utilize all of these capital loss carryforwards. Any ultimate utilization of capital loss carryforwards for which valuation allowances were established through purchase accounting would adjust goodwill.

During 2006 a ($15) million net change in valuation allowance occurred due to Pennsylvania tax law changes and the utilization of capital loss carryforwards to offset realized capital gains resulting in a $1 million adjustment to goodwill. The valuation allowances also include $48 million for deferred tax assets associated with impairment losses related to certain assets.

FirstEnergy has pre-tax net operating loss carryforwards for state and local income tax purposes of approximately $1.034 billion of which $184 million is expected to be utilized. The associated deferred tax assets are $11 million. These losses expire as follows:

Expiration Period	Amount
	*(in millions)*
2007-2011	$	332
2012-2016		37
2017-2021		297
2022-2026		368
	$	1,034

3. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. The trusteed plans provide defined benefits based on years of service and compensation levels. The Company'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 2016.

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. The Company recognizes 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, 2006.

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	2006			2005			2006			2005
	*(In millions)*
Change in benefit obligation
Benefit obligation as of January 1	$	4,750		$	4,364		$	1,884		$	1,930
Service cost		83			77			34			40
Interest cost		266			254			105			111
Plan participants’ contributions		-			-			20			18
Plan amendments		3			15			(620	)		(312	)
Medicare retiree drug subsidy		-			-			6			-
Actuarial (gain) loss		33			310			(119	)		197
Benefits paid		(274	)		(270	)		(109	)		(100	)
Benefit obligation as of December 31	$	4,861		$	4,750		$	1,201		$	1,884

Change in fair value of plan assets
Fair value of plan assets as of January 1	$	4,524		$	3,969		$	573		$	564
Actual return on plan assets		568			325			69			33
Company contribution		-			500			54			58
Plan participants’ contribution		-			-			20			18
Benefits paid		(274	)		(270	)		(109	)		(100	)
Fair value of plan assets as of December 31	$	4,818		$	4,524		$	607		$	573

Funded status	$	(43	)	$	(226	)	$	(594	)	$	(1,311	)

Accumulated benefit obligation	$	4,447		$	4,327

Amounts Recognized in the Statement of
Financial Position
Noncurrent assets	$	-		$	1,023		$	-		$	-
Current liabilities		-			-			-			-
Noncurrent liabilities		(43	)		-			(594	)		(1,057	)
Net asset (liability) as of December 31	$	(43	)	$	1,023		$	(594	)	$	(1,057	)

Amounts Recognized in
Accumulated Other Comprehensive Income
Prior service cost (credit)	$	63		$	-		$	(1,190	)	$	-
Actuarial loss		982			-			702			-
Net amount recognized	$	1,045		$	-		$	(488	)	$	-

Assumptions Used to Determine
Benefit Obligations As of December 31
Discount rate		6.00	%		5.75	%		6.00	%		5.75	%
Rate of compensation increase		3.50	%		3.50	%

Allocation of Plan Assets
As of December 31
Asset Category
Equity securities		64	%		63	%		72	%		71	%
Debt securities		29			33			26			27
Real estate		5			2			1			-
Private equities		1			-			-			-
Cash		1			2			1			2
Total		100	%		100	%		100	%		100	%

Estimated Items to be Amortized in 2007 Net
Periodic Pension Cost from Accumulated		Pension		Other
Other Comprehensive Income		Benefits		Benefits
	*(In millions)*
Prior service cost (credit)	$	10	$	(149	)
Actuarial loss	$	41	$	45

	Pension Benefits									Other Benefits
Components of Net Periodic Benefit Costs	2006			2005			2004			2006			2005			2004
	*(In millions)*
Service cost	$	83		$	77		$	77		$	34		$	40		$	36
Interest cost		266			254			252			105			111			112
Expected return on plan assets		(396	)		(345	)		(286	)		(46	)		(45	)		(44	)
Amortization of prior service cost		10			8			9			(76	)		(45	)		(40	)
Recognized net actuarial loss		58			36			39			56			40			39
Net periodic cost	$	21		$	30		$	91		$	73		$	101		$	103

Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost	Pension Benefits										Other Benefits
for Years Ended December 31		2006			2005			2004			2006			2005			2004
Discount rate		5.75	%		6.00	%		6.25	%		5.75	%		6.00	%		6.25	%
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	%

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 the Company'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.

Assumed Health Care Cost Trend Rates
As of December 31	2006			2005
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)		2011-2013			2010-2012

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	$	6	$	(5	)
Effect on accumulated postretirement benefit obligation	$	33	$	(29	)

Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets:

	Pension		Other
	Benefits		Benefits
	*(In millions)*
2007	$	247	$	91
2008		249		91
2009		256		94
2010		269		98
2011		280		101
Years 2012- 2016		1,606		537

FirstEnergy also maintains two unfunded benefit plans, an Executive Deferred Compensation Plan (EDCP) and Supplemental Executive Retirement Plan (SERP) under which non-qualified supplemental pension benefits are paid to certain employees in addition to amounts received under the Company’s qualified retirement plan, which is subject to IRS limitations on covered compensation. See Note 4(C) for a discussion regarding the stock compensation component of the EDCP. The net periodic pension cost of these plans was $21 million, $16 million and $14 million for the years ended 2006, 2005 and 2004, respectively. The projected benefit obligation and the unfunded status was $170 million and $161 million as of December 31, 2006 and 2005, respectively. The net liability recognized was $301 million and $238 million as of December 31, 2006 and 2005, respectively, and is included in the caption “retirement benefits” on the Consolidated Balance Sheets. The benefit payments, which reflect future service, as appropriate, are expected to be as follows:

	Benefit
	Payments
	*(In millions)*
2007	$	7
2008		9
2009		8
2010		8
2011		9
Years 2012- 2016		61

4. STOCK-BASED COMPENSATION PLANS

FirstEnergy has four stock-based compensation programs: LTIP; EDCP; ESOP; and DCPD. FirstEnergy has also assumed responsibility for several stock-based plans through acquisitions. In 2001, FirstEnergy assumed responsibility for two stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under GPU’s Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which ranged from one to four years. As of February 2006, all awards under the MYR Plan were exercised. The Centerior Equity Plan (CE Plan) is an additional stock-based plan administered by FirstEnergy for which it assumed responsibility as a result of the acquisition of Centerior Energy Corporation in 1997. All options are fully vested under the CE Plan, and no further awards are permitted. There were no outstanding options at December 31, 2006 under the CE Plan.

Effective January 1, 2006, FirstEnergy adopted SFAS 123(R), which requires the expensing of stock-based compensation. Under SFAS 123(R), all share-based compensation cost is measured at the grant date based on the fair value of the award, and is recognized as an expense over the employee’s requisite service period. FirstEnergy adopted the modified prospective method, under which compensation expense recognized in the year ended December 31, 2006 included the expense for all share-based payments granted prior to but not yet vested as of January 1, 2006. Results for prior periods were not restated.

Prior to the adoption of SFAS 123(R) on January 1, 2006, FirstEnergy’s LTIP, EDCP, ESOP, and DCPD stock-based compensation programs were accounted for under the recognition and measurement principles of APB 25 and related interpretations. Under APB 25, no compensation expense was reflected in net income for stock options as all options granted under those plans have exercise prices equal to the market value of the underlying common stock on the respective grant dates, resulting in substantially no intrinsic value. The pro forma effects on net income for stock options were instead disclosed in a footnote to the financial statements. Under APB 25 and SFAS 123(R), compensation expense was recorded in the income statement for restricted stock, restricted stock units, performance shares and the EDCP and DCPD programs. No stock options have been granted since the third quarter of 2004. Consequently, the impact of adopting SFAS 123(R) was not material to FirstEnergy’s net income and earnings per share in the year ended December 31, 2006.

(A)

LTIP

FirstEnergy’s LTIP includes four stock-based compensation programs - restricted stock, restricted stock units, stock options, and performance shares. During 2005, FirstEnergy began issuing restricted stock units and reduced its use of stock options.

Under FirstEnergy’s LTIP, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options, restricted stock and restricted stock units have currently been designated to pay out in common stock, with vesting periods ranging from two months to ten years. Performance share awards are currently designated to be paid in cash rather than common stock and therefore do not count against the limit on stock-based awards. As of December 31, 2006, 3.3 million shares were available for future awards.

Restricted Stock and Restricted Stock Units

Eligible employees receive awards of FirstEnergy common stock or stock units subject to restrictions. Those restrictions lapse over a defined period of time or based on performance. Dividends are received on the restricted stock and are reinvested in additional shares. Restricted common stock grants under the FE Plan were as follows:

	2006		2005		2004
Restricted common shares granted	229,271		356,200		62,370
Weighted average market price	$	53.18	$	41.52	$	40.69
Weighted average vesting period (years)		4.47		5.4		2.7
Dividends restricted		Yes		Yes		Yes

Vesting activity for restricted common stock during the year was as follows:


		Weighted
	Number	Average
	of	Grant-Date
Restricted Stock	Shares	Fair Value
Nonvested at January 1, 2006	424,411	$	41.43
Nonvested at December 31, 2006	629,482		45.79
Vested in 2006	19,200		38.80

There are two types of restricted stock unit awards -- discretionary-based and performance-based. With the discretionary-based, the Company grants the right to receive, at the end of the period of restriction, a number of shares of common stock of FirstEnergy equal to the number of restricted stock units set forth in each agreement. With performance-based, FirstEnergy grants the right to receive, at the end of the period of restriction, a number of shares of common stock of FirstEnergy equal to the number of restricted stock units set forth in the agreement subject to adjustment based on FirstEnergy’s stock performance.

	2006		2005		2004
Restricted common share units granted		440,676		477,920		-
Weighted average vesting period (years)		3.32		3.32		-

Vesting activity for restricted stock units during the year was as follows:


		Weighted
	Number	Average
	of	Grant-Date
Restricted Stock Units	Shares	Fair Value
Nonvested at January 1, 2006	464,924	$	41.44
Nonvested at December 31, 2006	887,794		45.97
Granted during 2006	440,676		50.92
Vested in 2006	6,026		41.42

Compensation expense recognized for restricted stock and restricted stock units during 2006 approximated $17 million. Compensation expense recognized for restricted stock during 2005 and 2004 totaled $10 million and $2 million, respectively.

Stock Options

Stock options were granted to eligible employees allowing them to purchase a specified number of common shares at a fixed grant price over a defined period of time. Stock option activities under the FE Programs for the past three years were as follows:

			Weighted
	Number		Average
	of		Exercise
Stock Option Activities	Options		Price
Balance, January 1, 2004	$	13,648,869	$	29.27
(1,919,662 options exercisable)				29.67

Options granted		3,373,459		38.77
Options exercised		3,622,148		26.52
Options forfeited		167,425		32.58
Balance, December 31, 2004		13,232,755		32.40
(3,175,023 options exercisable)				29.07

Options granted		-		-
Options exercised		4,140,893		29.79
Options forfeited		225,606		34.37
Balance, December 31, 2005		8,866,256		33.57
(4,090,829 options exercisable)				31.97

Options granted		-		-
Options exercised		2,221,417		32.65
Options forfeited		26,550		33.36
Balance, December 31, 2006		6,618,289		33.88
(4,160,859 options exercisable)				32.85

Options outstanding by plan and range of exercise price as of December 31, 2006 were as follows:

			Options Outstanding						Options Exercisable
					Weighted						Weighted
	Range of				Average		Remaining				Average
FE Program	Exercise Prices		Shares		Exercise Price		Contractual Life		Shares		Exercise Price
FE plan	$	19.31 - $29.87		2,744,608	$	29.16		5.49		1,887,458	$	28.90
	$	30.17 - $39.46		3,848,267	$	37.31		6.49		2,247,987	$	36.27
GPU plan	$	23.75 - $35.92		25,414	$	24.29		3.37		25,414	$	24.29
Total				6,618,289	$	33.88		6.07		4,160,859	$	32.85

There were no stock options granted in 2006 or 2005. The weighted average fair value of options granted in 2004 are estimated below using the Black-Scholes option-pricing model and the following assumptions:

	2004
Fair value per option	$	6.72
Weighted average valuation assumptions:
Expected option term (years)		7.6
Expected volatility		26.25	%
Expected dividend yield		3.88	%
Risk-free interest rate		1.99	%

Prior to the adoption of SFAS 123(R) compensation expense for FirstEnergy stock options was based on intrinsic value, which equals any positive difference between FirstEnergy's common stock price on the option's grant date and the option's exercise price. The exercise prices of all stock options granted in 2004 equaled the market price of FirstEnergy's common stock on the options' grant dates. If fair value accounting were applied to FirstEnergy's stock options, net income and earnings per share would be reduced as summarized below.

	2005			2004
	*(In millions, except per share amounts)*
Net Income, as reported	$	861			$	878

Add back compensation expense
reported in net income, net of tax
(based on APB 25)*		32				21

Deduct compensation expense based
upon estimated fair value, net of tax*		(39	)			(35	)

Pro forma net income	$	854			$	864
Earnings Per Share of Common Stock -
Basic
As Reported	$	2.62			$	2.68
Pro Forma	$	2.60			$	2.64
Diluted
As Reported	$	2.61			$	2.67
Pro Forma	$	2.59			$	2.63

* Includes restricted stock, restricted stock units, stock options, performance shares, ESOP, EDCP and DCPD.

As noted above, FirstEnergy reduced its use of stock options beginning in 2005 and increased its use of performance-based, restricted stock units. FirstEnergy has not accelerated out-of-the-money options in anticipation of adopting SFAS 123(R) on January 1, 2006. As a result, all currently unvested stock options will vest by 2008. Compensation expense recognized for stock options during 2006 total $6 million.

Performance Shares

Performance shares are share equivalents and do not have voting rights. The shares track the performance of FirstEnergy's common stock over a three-year vesting period. During that time, dividend equivalents are converted into additional shares. The final account value may be adjusted based on the ranking of FirstEnergy stock performance to a composite of peer companies. Compensation expense recognized for performance shares during 2006, 2005 and 2004 totaled approximately $25 million, $7 million and $5 million, respectively.

(B) ESOP

An ESOP Trust funds most of the matching contribution for FirstEnergy's 401(k) savings plan. All full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. The ESOP borrowed $200 million from OE and acquired 10,654,114 shares of OE's common stock (subsequently converted to FirstEnergy common stock) through market purchases. Dividends on ESOP shares are used to service the debt. Shares are released from the ESOP on a pro rata basis as debt service payments are made.

In determining the amount of borrowing under the ESOP, assumptions were made including the size and growth rate of the Company's workforce, earnings, dividends, and trading price of common stock. In 2005, the ESOP loan was refinanced ($66 million principal amount) and its term was extended by three years. In 2006, 2005 and 2004, 922,978 shares, 588,004 shares and 864,151 shares, respectively, were allocated to employees with the corresponding expense recognized based on the shares allocated method. The fair value of 521,818 shares unallocated as of December 31, 2006 was approximately $31 million. Total ESOP-related compensation expense was calculated as follows:

	2006			2005			2004
	*(In millions)*
Base compensation	$	50		$	39		$	32
Dividends on common stock held by the ESOP and used to service debt		(11	)		(10	)		(9	)
Net expense	$	39		$	29		$	23

(C) EDCP

Under the EDCP, covered employees can direct a portion of their compensation, including annual incentive awards and/or long-term incentive awards, into an unfunded FirstEnergy stock account to receive vested stock units or into an unfunded retirement cash account. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy stock account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement (see Note 3). Interest is calculated on the cash allocated to the cash account and the total balance will pay out in cash upon retirement. Of the 1.3 million EDCP stock units authorized, 628,539 stock units were available for future awards as of December 31, 2006. Compensation expense recognized on EDCP stock units in 2006 and 2005 were approximately $5 million each year and approximately $2 million in 2004.

(D)

DCPD

Under the DCPD, directors can elect to allocate all or a portion of their cash retainers, meeting fees and chair fees to deferred stock or deferred cash accounts. If the funds are deferred into the stock account, a 20% match is added to the funds allocated. The 20% match and any appreciation on it are forfeited if the director leaves the Board within three years from the date of deferral for any reason other than retirement, disability, death, upon a change in control, or when a director is ineligible to stand for re-election. Compensation expense is recognized for the 20% match over the three-year vesting period. Directors may also elect to defer their equity retainers into the deferred stock account; however, they do not receive a 20% match on that deferral. DCPD expenses recognized in 2006 and 2005 were approximately $3 million each year and $4 million in 2004. The net liability recognized was $5 million as of December 31, 2006 and 2005 and is included in the caption “retirement benefits” on the Consolidated Balance Sheets.

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 in the caption "short-term borrowings", which approximates their fair market value. 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:

	2006				2005
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	*(In millions)*
Long-term debt	$	10,321	$	10,725	$	10,097	$	10,576
Subordinated debentures to affiliated trusts		103		105		103		140
	$	10,424	$	10,830	$	10,200	$	10,716

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 the Companies' ratings.

(B)

Investments

Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities. The Companies and NGC 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 security’s fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. The following table provides the approximate fair value and related carrying amounts of investments excluding the nuclear decommissioning trust fund investments and investments of $265 million and $244 million for 2006 and 2005 excluded by SFAS 107, “Disclosures about Fair Values of Financial Instruments”, as of December 31:

		2006				2005
		Carrying		Fair		Carrying		Fair
		Value		Value		Value		Value
		*(In millions)*
Restricted funds		$	11	$	11	$	-	$	-
Notes receivable			70		67		68		67
Debt securities:
	- Government obligations ⁽¹⁾		383		379		374		370
	- Corporate debt securities		3		5		3		40
	- Lease obligation bonds		811		908		890		997
Total debt securities			1,197		1,292		1,267		1,407
Equity securities			9		9		20		20
		$	1,287	$	1,379	$	1,355	$	1,497

(1)	Excludes $5 million of cash in 2006

The table above includes restricted funds, notes receivable, nuclear fuel disposal trust investments, NUG trust investments, investments in lease obligation bonds, and other miscellaneous investments. The carrying value of the restricted funds is assumed to approximate market value. 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 2007 to 2040. The nuclear fuel disposal and NUG trust investments consist of debt securities classified as available-for-sale with the fair value determined based on quoted market prices. The investments in lease obligation bonds are accounted for as held-to-maturity securities and the fair value is based on present value of the cash inflows based on the yield to maturity similar to the notes receivable. The maturity dates range from 2007 to 2017.

The following table provides the amortized cost basis, unrealized gains and losses, and fair values for the investments in debt and equity securities above excluding the restricted funds and notes receivable:

	2006								2005
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	*(In millions)*
Debt securities	$	1,197	$	100	$	5	$	1,292	$	1,267	$	145	$	5	$	1,407
Equity securities		9		-		-		9		20		-		-		20
	$	1,206	$	100	$	5	$	1,301	$	1,287	$	145	$	5	$	1427

Proceeds from the sale of the investments detailed above, realized gains and losses on those sales, and interest and dividend income for the three years ended December 31, 2006 were as follows:

	2006		2005		2004
	*(In millions)*
Proceeds from sales	$	1,442	$	4,732	$	17,564
Realized gains		-		-		4
Realized losses		4		2		1
Interest and dividend income		15		14		11

(C) Nuclear Decommissioning Trust Fund Investments

Nuclear decommissioning trust investments are classified as available-for-sale with the fair value representing quoted market prices. The Companies and NGC have no securities held for trading purposes. Upon adoption of FSP SFAS 115-1 and SFAS 124-1, FirstEnergy began expensing unrealized losses on available-for-sale securities held in the 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. Approximately $13 million of unrealized losses on these available-for-sale securities were reclassified from OCI to earnings upon adoption of these pronouncements. The following table provides the carrying value, which equals fair value of the nuclear decommissioning trust funds as of December 31, 2006 and 2005, respectively. The fair value was determined using the specific identification method.

		2006						2005
	(In millions)
Debt securities:
- Government obligations			$	526				$	561
- Corporate debt securities				153					125
- Mortgage-backed securities				12					-
				691					686
Equity securities				1,284					1,066
			$	1,975	⁽¹⁾	⁽¹	⁾	$	1,752

⁽¹⁾ Excludes $2 million of receivables and payables

The following table summarizes the amortized cost basis, unrealized gains and losses and fair values for decommissioning trust investments as of December 31:

	2006									2005
	Cost		Unrealized		Unrealized		Fair			Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value			Basis		Gains		Losses		Value
	*(In millions)*
Debt securities	$	681	$	10	$	-	$	691		$	681	$	12	$	7	$	686
Equity securities		952		332		-		1,284			898		190		22		1,066
	$	1,633	$	342	$	-	$	1,975	( 1) ¹⁾	$	1,579	$	202	$	29	$	1,752

⁽¹⁾ Excludes $2 million of receivables and payables

Unrealized gains applicable to OE's, TE's and the majority of NGC's decommissioning trusts are recognized in OCI in accordance with SFAS 115, as fluctuations in fair value will eventually affect 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.

Proceeds from the sale of decommissioning trust investments, realized gains and losses on those sales, and interest and dividend income for the three years ended December 31, 2006 were as follows:

	2006		2005		2004
	*(In millions)*
Proceeds from sales	$	1,569	$	1,419	$	1,234
Realized gains		121		133		144
Realized losses		101		58		43
Interest and dividend income		55		49		45

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.

(D)

DERIVATIVES-

FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criterion. Derivatives that meet that criterion are accounted for on the accrual basis. The changes in the fair value of derivative instruments that do not meet the normal purchase and sales criterion are recorded in current earnings, in AOCL, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness.

FirstEnergy's primary ongoing hedging activities involve cash flow hedges of electricity and natural gas purchases and anticipated interest payments associated with future debt issuances. The effective portion of such hedges is initially recorded in equity as AOCL and is subsequently recorded in net income, as an expense, when the underlying hedged commodities are delivered or interest payments are made. AOCL as of December 31, 2006 includes a net deferred loss of $58 million for derivative hedging activity. The $20 million decrease from the December 31, 2005 balance of $78 million consists of a $20 million decrease due to net hedge losses included in earnings, with current hedging activity having no effect on net income during the year. Approximately $19 million (after tax) of the current net deferred loss on derivative instruments in AOCL is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments will continue to fluctuate from period to period based on various market factors. Gains and losses from any ineffective portion of the cash flow hedge are recorded directly to earnings. The impact of ineffectiveness on earnings during 2006 and 2005 was not material.

FirstEnergy entered into interest rate derivative transactions in 2001 to hedge a portion of the anticipated interest payments on debt related to the GPU acquisition. Gains and losses from hedges of anticipated interest payments on acquisition debt are included in net income, as a component of interest expense, over the periods that hedged interest payments are made - 5, 10 and 30 years. In 2006, a $23 million loss was amortized to interest expense.

FirstEnergy has entered into fixed-for-floating interest rate swap agreements, whereby FirstEnergy receives fixed cash flows based on the fixed coupons of the hedged securities and pays variable cash flows based on short-term variable market interest rates (3 and 6-month LIBOR indices). These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, fixed interest rates received, and interest payment dates match those of the underlying obligations. During 2006, FirstEnergy unwound swaps with a total notional amount of $350 million for which it incurred $1 million in cash losses during 2006. The losses will be recognized over the remaining maturity of each respective hedged security as increased interest expense. As of December 31, 2006, the aggregate notional value of interest rate swap agreements outstanding was $750 million.

During 2005, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the future planned issuances of fixed-rate, long-term debt securities for one or more of its consolidated entities in 2006 - 2008. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of December 31, 2006, FirstEnergy had entered into forward swaps with an aggregate notional amount of $300 million. As of December 31, 2006, the forward swaps had a fair value of ($4) million.

6.	LEASES

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

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.

Consistent with the regulatory treatment, 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, 2006 are summarized as follows:

	2006		2005		2004
	*(In millions)*
Operating leases
Interest element	$	160	$	171	$	175
Other		190		162		140
Capital leases
Interest element		1		1		1
Other		2		2		3
Total rentals	$	353	$	336	$	319

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 PNBV and Shippingport arrangements effectively reduce lease costs related to those transactions (see Note 7).

The future minimum lease payments as of December 31, 2006 are:

			Operating Leases
	Capital		Lease		Capital
	Leases		Payments		Trusts		Net
	*(In millions)*
2007	$	1	$	335	$	131	$	204
2008		1		332		105		227
2009		1		334		112		222
2010		1		334		121		213
2011		1		324		121		203
Years thereafter		2		1,748		519		1,229
Total minimum lease payments		7	$	3,407	$	1,109	$	2,298
Executory costs		-
Net minimum lease payments		7
Interest portion		2
Present value of net minimum		5
lease payments
Less current portion		1
Noncurrent portion	$	4

FirstEnergy has 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 is being amortized on a straight-line basis through the end of the lease term in 2017 (approximately $37 million per year). The total above-market lease obligation of $755 million associated with the Bruce Mansfield Plant is being amortized on a straight-line basis through the end of 2016 (approximately $48 million per year). As of December 31, 2006, the above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant totaled $852 million, of which $85 million is classified as current liabilities.

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. FirstEnergy adopted FIN 46R for special-purpose entities as of December 31, 2003 and for all other entities in the first quarter of 2004. FirstEnergy and its subsidiaries consolidate a VIE when FirstEnergy is determined to be the VIE's primary beneficiary as defined by FIN 46R.

Leases

FirstEnergy’s consolidated financial statements include PNBV and Shippingport, VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with the sale and leaseback transactions discussed in Note 6. PNBV is included in the consolidated financial statements of OE and Shippingport is included in the consolidated financial statements of CEI.

PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.

OE, CEI and TE are exposed to losses under the applicable sale and leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $835 million, $955 million, and $955 million, respectively, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the applicable sale and leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $631 million, $97 million and $503 million, respectively, that would not be payable if the casualty value payments are made.

Power Purchase Agreements

In accordance with FIN 46R, FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Companies and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately 30 long-term power purchase agreements with NUG entities. The agreements were structured pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. As required by FIN 46R, FirstEnergy periodically requests from these eight entities the information necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R.

Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it incurs for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. As of December 31, 2006, the net above-market loss liability recognized for these eight NUG agreements was $171 million. Purchased power costs from these entities during 2006, 2005 and 2004 were $171 million, $180 million and $175 million, respectively.

8. DIVESTITURES

In 2006, FirstEnergy sold its remaining FSG subsidiaries (Roth Bros., Hattenbach, Dunbar, Edwards and RPC) for an aggregate net after-tax gain of $2.2 million. Based on SFAS 144 criteria, Hattenbach, Dunbar, Edwards, and RPC are accounted for as discontinued operations as of December 31, 2006. Roth Bros. did not meet the criteria for classification as discontinued operations as of December 31, 2006 (see Note 2(J)).

In March 2006, FirstEnergy sold 60% of its interest in MYR for an after-tax gain of $0.2 million. In June 2006, an additional 1.67% interest was sold pursuant to the same March 2006 sale agreement. As a result of the March sale, FirstEnergy deconsolidated MYR in the first quarter of 2006 and accounted for its remaining interest under the equity method. In November 2006, FirstEnergy sold the remaining 38.33% interest in MYR for an after-tax gain of $8.6 million. In accordance with SFAS 144, the income for the time period that MYR was accounted for as an equity method investment has not been included in discontinued operations; however, in accordance with EITF 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations , results for all reporting periods prior to the initial sale in March 2006, including the portion of 2006 prior to the sale are reported as discontinued operations (see Note 2(J)).

In 2005, FirstEnergy sold three FSG subsidiaries - Elliott-Lewis, Spectrum Control Systems and L. H. Cranston and Sons - and an MYR subsidiary - Power Piping Company, resulting in an aggregate after-tax gain of $13 million. All of these sales, with the exception of Spectrum Control Systems met the discontinued operations criteria (see Note 2(J)).

In March 2005, FES completed the sale of its retail natural gas business for an after-tax gain of $5 million. Also in March 2005, FirstEnergy sold 51% of its interest in FirstCom, resulting in an after-tax gain of $4 million. FirstEnergy accounts for its remaining 31.85% interest in FirstCom on the equity basis.

FirstEnergy sold its 50% interest in GLEP in June 2004. Proceeds of $220 million included cash of $200 million and the right, valued at $20 million, to participate for up to a 40% interest in future wells in Ohio. This transaction produced an after-tax loss of $7 million, including the benefits of prior tax capital losses that had been previously fully reserved, which offset the capital gain from the sale.

FirstEnergy completed the sale of its international operations in January 2004 with the sales of its remaining 20.1% interest in Avon (parent of Midlands Electricity in the United Kingdom) and its 28.67% interest in TEBSA, for $12 million. No gain or loss was recognized upon the sales in 2004. Avon and TEBSA were originally acquired as part of FirstEnergy's November 2001 merger with GPU.

9. OHIO TAX LEGISLATION

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

OE	$	32
CEI		4
TE		18
Other FirstEnergy subsidiaries		(2	)
Total FirstEnergy	$	52

Income tax expenses were reduced (increased) 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):

OE	$	3
CEI		5
TE		1
Other FirstEnergy subsidiaries		(3	)
Total FirstEnergy	$	6

10. REGULATORY MATTERS

(A) RELIABILITY INITIATIVES-

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training and emergency response preparedness recommended for completion in 2004. On July 14, 2004, NERC independently verified that FirstEnergy had implemented the various initiatives to be completed by June 30 or summer 2004, with minor exceptions noted by FirstEnergy, which exceptions are now essentially complete. FirstEnergy is proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new equipment or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability entities may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future, which could require additional, material expenditures.

As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L’s ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L’s Planning and Operations and Maintenance programs and practices (Focused Audit). On February 11, 2005, JCP&L met with the DRA to discuss reliability improvements. The SRM completed his work and issued his final report to the NJBPU on June 1, 2006. JCP&L filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

The EPACT provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC’s review. On February 3, 2006, the FERC adopted a rule establishing certification requirements for the ERO, as well as regional entities envisioned to assume compliance monitoring and enforcement responsibility for the new reliability standards. The FERC issued an order on rehearing on March 30, 2006, providing certain clarifications and essentially affirming the rule.

The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC’s certification requirements for the ERO. The NERC made a filing with the FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC approval of pro forma delegation agreements with regional reliability organizations (regional entities). The new FERC rule referred to above, further provides for reorganizing regional entities that would replace the current regional councils and for rearranging their relationship with the ERO. The “regional entity” may be delegated authority by the ERO, subject to FERC approval, for compliance and enforcement of reliability standards adopted by the ERO and approved by the FERC. The ERO filing was noticed on April 7, 2006 and comments and reply comments were filed in May, June and July 2006. On July 20, 2006, the FERC certified the NERC as the ERO to implement the provisions of Section 215 of the Federal Power Act and directed the NERC to make compliance filings addressing governance and non-governance issues and the regional delegation agreements. On September 18, 2006 and October 18, 2006, NERC submitted compliance filings addressing the governance and non-governance issues identified in the FERC ERO Certification Order, dated July 20, 2006. On October 30, 2006, the FERC issued an order accepting most of NERC’s governance filings. On January 18, 2007, the FERC issued an order largely accepting NERC’s compliance filings addressing non-governance issues, subject to an additional compliance filing requirement.

On April 4, 2006, NERC also submitted a filing with the FERC seeking approval of mandatory reliability standards, as well as for approval with the relevant Canadian authorities. These reliability standards are based, with some modifications and additions, on the current NERC Version 0 reliability standards. The reliability standards filing was subsequently evaluated by the FERC on May 11, 2006, leading to the FERC staff’s release of a preliminary assessment that cited many deficiencies in the proposed reliability standards. The NERC and industry participants filed comments in response to the Staff’s preliminary assessment. The FERC held a technical conference on the proposed reliability standards on July 6, 2006. The FERC issued a NOPR on the proposed reliability standards on October 20, 2006. In the NOPR, the FERC proposed to approve 83 of the 107 reliability standards and directed NERC to make technical improvements to 62 of the 83 standards approved. The 24 standards that were not approved remain pending at the FERC awaiting further clarification and filings by the NERC and regional entities. The FERC also provided additional clarification within the NOPR regarding the proposed application of final standards and guidance with regard to technical improvements of the standards. On November 15, 2006, NERC submitted several revised reliability standards and three new proposed reliability standards. Interested parties were provided the opportunity to comment on the NOPR (including the revised standards submitted by NERC in November) by January 3, 2007. Numerous parties, including FirstEnergy, filed comments on the NOPR on January 3, 2007. Mandatory reliability standards enforceable with penalties are expected to be in place by the summer of 2007. In a separate order issued October 24, 2006, the FERC approved NERC’s 2007 budget and business plan subject to certain compliance filings.

On November 29, 2006, NERC submitted an additional compliance filing with the FERC regarding the Compliance Monitoring and Enforcement Program (CMEP) along with the proposed Delegation Agreements between the ERO and the regional reliability entities. The FERC provided opportunity for interested parties to comment on the CMEP by January 10, 2007. FirstEnergy, as well as other parties, moved to intervene and submitted responsive comments on January 10, 2007. This filing is pending before the FERC.

The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils completed the consolidation of these regions into a single new regional reliability organization known as Reliability First Corporation. Reliability First began operations as a regional reliability council under NERC on January 1, 2006 and on November 29, 2006 filed a proposed Delegation Agreement with NERC to obtain certification consistent with the final rule as a “regional entity” under the ERO. All of FirstEnergy’s facilities are located within the Reliability First region.

On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security standards that replaced interim standards put in place in the wake of the September 11, 2001 terrorist attacks, and thirteen additional reliability standards. The security standards became effective on June 1, 2006, and the remaining standards will become effective throughout 2006 and 2007. NERC filed these proposed standards with the FERC and relevant Canadian authorities for approval. The cyber security standards were not included in the October 20, 2006 NOPR and are being addressed in a separate FERC docket. On December 11, 2006, the FERC Staff provided its preliminary assessment of these proposed mandatory reliability standards and again cited various deficiencies in the proposed standards, providing interested parties with the opportunity to comment on the assessment by February 12, 2007.

FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the October 20, 2006 NOPR, it appears that the FERC will adopt more strict reliability standards than those contained in the current NERC standards. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates. If FirstEnergy is unable to meet the reliability standards for its bulk power system in the future, it could have a material adverse effect on FirstEnergy’s and its subsidiaries’ financial condition, results of operations and cash flows.

(B) OHIO-

On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO’s concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court’s concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29 , 2007. I n their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. No further proceedings are scheduled at this time.

The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. Major provisions of the RCP include:

	Maintaining the existing level of base distribution rates through December 31, 2008 for OE and TE, and April 30, 2009 for CEI;

	Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;

	Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for OE and TE and as of December 31, 2010 for CEI;

	Reducing the deferred shopping incentive balances as of January 1, 2006 by up to $75 million for OE, $45 million for TE, and $85 million for CEI by accelerating the application of each respective company's accumulated cost of removal regulatory liability; and

	Recovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all OE and TE distribution and transmission customers through a fuel recovery mechanism. OE, TE, and CEI may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the amount collected through the fuel recovery mechanism.

On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. On January 10, 2006, the Ohio Companies filed a Motion for Clarification seeking clarity on a number of issues. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies’ requests to:

	Recognize fuel and distribution deferrals commencing January 1, 2006;

	Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff;

	Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and

	Clarify that distribution expenditures do not have to be “accelerated” in order to be deferred.

The PUCO approved the Ohio Companies’ methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies’ Motion. On February 3, 2006, several other parties filed applications for rehearing, which the PUCO denied on March 1, 2006. Two of these parties subsequently filed notices of appeal with the Supreme Court of Ohio. The Ohio Supreme Court scheduled this case for oral argument on February 27, 2007. On January 31, 2007, the Ohio Companies filed a stipulation which, among other matters and subject to PUCO approval, affirmed that the supplemental stipulation in the RCP would be implemented. This stipulation was approved by the PUCO on February 14, 2007.

On December 30, 2004, the Ohio Companies filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application sought recovery of these costs beginning January 1, 2006. The Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues recovered from January 1 through June 30, 2006 were approximately $54 million. That amount included the recovery of a portion of the 2005 deferred MISO expenses as described below. On April 27, 2006, the Ohio Companies filed the annual update rider to determine revenues ($124 million) from July 2006 through June 2007. The filed rider went into effect on July 1, 2006.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. On January 20, 2006, the OCC sought rehearing of the PUCO’s approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of the Ohio Companies' case with a similar case involving Dayton Power & Light Company. Oral arguments were heard on May 10, 2006. On November 29, 2006, the Ohio Supreme Court issued its opinion upholding the PUCO’s determination that the Ohio Companies may defer transmission and ancillary service related costs incurred on and after December 30, 2004. The Ohio Supreme Court also determined that the PUCO erred when it denied the OCC intervention, but further ruled that such error did not prejudice OCC and, therefore, the Ohio Supreme Court did not reverse or remand the PUCO on this ground. The Ohio Supreme Court also determined that the OCC’s appeal was not premature. No party filed a motion for reconsideration with the Ohio Supreme Court.

(C) PENNSYLVANIA-

A February 2002 Commonwealth Court of Pennsylvania decision affirmed the June 2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanded the issues of quantification and allocation of merger savings to the PPUC and denied Met-Ed and Penelec the rate relief initially approved in the PPUC decision. On May 4, 2006, the PPUC consolidated the merger savings proceeding with the April 10, 2006 comprehensive rate filing proceeding discussed below. On January 11, 2007, the PPUC entered an order in that rate filing proceeding and determined that no merger savings from prior years should be considered in determining customers’ rates.

On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005. Met-Ed and Penelec sought to consolidate this proceeding (and modified their request to provide deferral of 2006 transmission-related costs only) with the comprehensive rate filing made on April 10, 2006, described below. On May 4, 2006, the PPUC approved the modified request.

Met-Ed and Penelec have been purchasing a portion of their PLR requirements from FES through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy costs during the term of these agreements with FES.

On April 7, 2006, the parties entered into a Tolling Agreement that arose from FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7 Tolling Agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec Transition Rate cases filed April 10, 2006, described below. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a Supplier Master Agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that substantially exceed the fixed price in the partial requirements agreements.

Based on the outcome of the Transition Rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. 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 allows Met-Ed and Penelec to sell the output of NUG generation to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties have also separately terminated the Tolling, Suspension and Supplier Master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the Master Supplier Agreement will now be provided under the restated partial requirements 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 its fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.

Met-Ed and Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals was approved, the filing would have increased annual revenues 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 is phased out in accordance with the April 7, 2006 Tolling Agreement described above. Met-Ed and Penelec also requested approval of the January 12, 2005 petition for the deferral of transmission-related costs discussed above, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider similar to that implemented in Ohio. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. Hearings were held in late August 2006 and briefing occurred in September and October. The ALJs issued their Recommended Decision on November 2, 2006.

The PPUC entered its Opinion and Order in the rate filing proceeding on January 11, 2007 . The Order approved the recovery of transmission costs, including the 2006 deferral, 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 in 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 expenses and the 2006 transmission deferral. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and in January 2007, they recognized income of $27 million to establish a regulatory asset for the previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% 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 congestion, transmission deferrals and rate design issues. The PPUC on February 8, 2007 entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court is tolled until 30 days after the PPUC enters a subsequent order ruling on the substantive issues raised in the petitions.

As of December 31, 2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $303 million and $70 million, respectively. Penelec’s $70 million deferral is subject to final resolution of an IRS settlement associated with NUG trust fund proceeds. 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 the PPUC’s 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 are scheduled for late February 2007. It is not known when the PPUC may issue a final decision in this matter.

On February 1, 2007 the Governor of Pennsylvania proposed an Energy Independence Strategy (EIS). The EIS includes four pieces of preliminary draft 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 programs to meet demand growth, a requirement that electric distribution companies acquire power through a "Least Cost Portfolio", the utilization of micro-grids and a three year phase-in of rate increases. Since the EIS has only recently been proposed, the final form of any legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

(D) NEW JERSEY-

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of December 31, 2006, the accumulated deferred cost balance totaled approximately $369 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval to securitize the July 31, 2003 deferred balance. On June 8, 2006, the NJBPU approved JCP&L’s request to issue securitization bonds associated with BGS stranded cost deferrals. On August 10, 2006, JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, issued $182 million of transition bonds with a weighted average interest rate of 5.5%.

On December 2, 2005, JCP&L filed its request for recovery of $165 million of actual above-market NUG costs incurred from August 1, 2003 through October 31, 2005 and forecasted above-market NUG costs for November and December 2005. On February 23, 2006, JCP&L filed updated data reflecting actual amounts through December 31, 2005 of $154 million of costs incurred since July 31, 2003. On July 18, 2006, JCP&L further requested an additional $14 million of costs that had been eliminated from the securitized amount. A Stipulation of Settlement was signed by all parties, approved by the ALJ and adopted by the NJBPU in its Order dated December 6, 2006. The Order approves an annual $110 million increase in NUGC rates designed to recover deferred costs incurred since August 1, 2003, and a portion of costs incurred prior to August 1, 2003 that were not securitized. The Order requires that JCP&L absorb any net annual operating losses associated with the Forked River Generating Station. In the Settlement, JCP&L also agreed not to seek an increase to the NUGC to become effective before January 2010, unless the deferred balance exceeds $350 million any time after June 30, 2007.

Reacting to the higher closing prices of the 2006 BGS fixed rate auction, the NJBPU, on March 16, 2006, initiated a generic proceeding to evaluate the auction process and potential options for the future. On April 6, 2006, initial comments were submitted. A public meeting was held on April 21, 2006 and a legislative-type hearing was held on April 28, 2006. On June 21, 2006, the NJBPU approved the continued use of a descending block auction for the Fixed Price Residential Class. JCP&L filed its 2007 BGS company specific addendum on July 10, 2006. On October 27, 2006, the NJBPU approved the auction format to procure the 2007 Commercial Industrial Energy Price as well as the specific rules for both the Fixed Price and Commercial Industrial Energy Price auctions. These rules were essentially unchanged from the prior auctions.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to the Ratepayer Advocate’s comments. 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 PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. 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. Comments on the alternative proposal were submitted on June 15, 2006. On November 3, 2006, the NJPBU Staff circulated a revised draft proposal to interested stakeholders.

New Jersey statutes require that the state periodically undertake a planning process, known as the Energy Master Plan (EMP), to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments.

In October 2006 the current EMP process was initiated with the issuance of a proposed set of objectives which, as to electricity, included the following:

Reduce the total projected electricity demand by 20% by 2020;
Meet 22.5% of the State’s 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 by 2020;
Unit prices for electricity should remain no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia); and
Eliminate transmission congestion by 2020

Comments on the objectives and participation in the development of the EMP have been solicited and a number of working groups have been formed to attain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected in the summer of 2007. A final draft of the EMP is expected to be presented to the Governor in the fall of 2007 with further public hearings anticipated in early 2008. At this time FirstEnergy cannot predict the outcome of this process nor determine its impact.

(E) FERC MATTERS-

On March 28, 2006, ATSI and MISO filed with the FERC a request to modify ATSI’s Attachment O formula rate to include revenue requirements associated with recovery of deferred Vegetation Management Enhancement Program (VMEP) costs. ATSI estimated that it may defer approximately $54 million of such costs over a five-year period. Approximately $42 million has been deferred as of December 31, 2006. The effective date for recovery was June 1, 2006. The FERC conditionally approved the filing on May 22, 2006, and on July 14, 2006 FERC accepted the ATSI compliance filing. A request for rehearing of the FERC’s May 22, 2006 Order was denied by FERC on October 25, 2006. The estimated annual revenues to ATSI from the VMEP cost recovery is $12 million for each of the five years beginning June 1, 2006.

On January 24, 2006, ATSI and MISO filed a request with the FERC to correct ATSI’s Attachment 0 formula rate to reverse revenue credits associated with termination of revenue streams from transitional rates stemming from FERC’s elimination of RTOR between the Midwest ISO and PJM. Revenues formerly collected under these transitional rates were included in, and served to reduce, ATSI’s zonal transmission rate under the Attachment O formula. Absent the requested correction, elimination of these revenue credits would not be fully reflected in ATSI’s formula rate until June 1, 2008. On March 16, 2006, the FERC approved the revenue credit correction without suspension, effective April 1, 2006. One party sought rehearing of the FERC's order, which was denied on June 27, 2006. No petition for review of the FERC’s decision was filed. The estimated revenue impact of the correction mechanism is approximately $37 million for the period June 1, 2006 though May 31, 2007.

On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The Presiding Judge issued an Initial Decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the Initial Decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in early 2007.

On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to refund and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order. On March 20, 2006, a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued an order approving this settlement on April 19, 2006. Hearings in the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial Decision was issued by the ALJ. The ALJ adopted the FERC Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate. The ALJ recommended an April 1, 2006 effective date for this change in rate design. If the FERC accepts this recommendation, the transmission rate applicable to many load zones in PJM would increase. FirstEnergy believes that significant additional transmission revenues would have to be recovered from the JCP&L, Met-Ed and Penelec transmission zones within PJM. JCP&L, Met-Ed and Penelec, as part of the Responsible Pricing Alliance, filed a brief addressing the Initial Decision on August 14, 2006 and September 5, 2006. The case will be reviewed by the FERC with a decision anticipated in early 2007.

On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies at a price equal to the retail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio CBP results in a lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006.

On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticized the Ohio CBP, and required FES to submit additional evidence in support of the reasonableness of the prices charged in the power sales agreements. On July 14, 2006, the Chief Judge granted the joint motion of FES and the Trial Staff to appoint a settlement judge in this proceeding and the procedural schedule was suspended pending settlement discussions among the parties. A settlement conference was held on September 5, 2006. FES and the Ohio Companies, Penn, and the PUCO, along with other parties, reached an agreement to settle the case. The settlement was filed with the FERC on October 17, 2006, and was unopposed by the remaining parties, including the FERC Trial Staff. This settlement was accepted by the FERC on December 8, 2006.

The terms of the settlement provide for modification of both the Ohio and Penn power supply agreements with FES. Under the Ohio power supply agreement, separate rates are established for the Ohio Companies’ PLR requirements; special retail contract requirements, wholesale contract requirements, and interruptible buy-through retail load requirements. For their PLR and special retail contract requirements, the Ohio Companies will pay FES no more than the lower of (i) the sum of the retail generation charge, the rate stabilization charge, the fuel recovery mechanism charge, and FES’ actual incremental fuel costs for such sales; or (ii) the wholesale price cap. Different wholesale price caps are imposed for PLR sales, special retail contracts, and wholesale contracts. The wholesale price for interruptible buy-through retail load requirements is limited to the actual spot price of power obtained by FES to provide this power. FES billed the Ohio Companies for the additional amount payable to FES for incremental fuel costs on power supplied during 2006. The total power supply cost billed by FES was lower in each case than the wholesale price caps specified in the settlement accepted by the FERC. In addition, pursuant to the settlement, the wholesale rate charged by FES under the Penn power supply agreement can be no greater than the generation component of charges for retail PLR load in Pennsylvania. The modifications to the Ohio and Pennsylvania power supply agreements became effective January 1, 2006. The Penn supply agreement subject to the settlement expired at midnight on December 31, 2006.

As a result of Penn’s PLR competitive solicitation process approved by the PPUC for the period January 1, 2007 through May 31, 2008, FES was selected as the winning bidder for a number of the tranches for individual customer classes. The balance of the tranches will be supplied by unaffiliated power suppliers. On October 2, 2006, FES filed an application with the FERC under Section 205 of the Federal Power Act for authorization to make these affiliate sales to Penn. Interventions or protests were due on this filing on October 23, 2006. Penn was the only party to file an intervention in this proceeding. This filing was accepted by the FERC on November 15, 2006, and no requests for rehearing were filed.

On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market. MISO contends that the filing will integrate operating reserves into MISO’s existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch. The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO. MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region. MISO is targeting implementation for the second or third quarter of 2008. The FERC has established March 23, 2007, as the date for interested parties to submit comments addressing the filing. The filing has not yet been fully evaluated to assess its impact on FirstEnergy's operations.

On February 16, 2007, the FERC issued a final rule that revises its decade-old open access transmission regulations and policies. The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule will not be effective until 60 days after publication in the Federal Register. The final rule has not yet been fully evaluated to assess its impact on FirstEnergy operations.

11. CAPITALIZATION

(A) COMMON STOCK-

Retained Earnings and Dividends

Under applicable federal law, FirstEnergy can pay cash dividends to its common shareholders only from retained or current earnings. As of December 31, 2006, FirstEnergy's unrestricted retained earnings were $2.8 billion. Each of FirstEnergy’s electric utility subsidiaries has authorization from the FERC to pay cash dividends to FirstEnergy from paid-in capital accounts, as long as its equity to total capitalization ratio (without consideration of retained earnings) remains above 35%. The articles of incorporation, indentures and various other agreements relating to the long-term debt and preferred stock of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common and preferred stock. As of December 31, 2006, none of these provisions materially restricted FirstEnergy’s subsidiaries’ ability to pay cash dividends to FirstEnergy.

On December 19, 2006, the Board of Directors increased the indicated annual common stock dividend to $2.00 per share, payable quarterly at a rate of $0.50 per share beginning in the first quarter of 2007. Dividends declared in 2006 were $1.85 which included three quarterly dividends of $0.45 per share paid in the second, third and fourth quarters of 2006 and a quarterly dividend of $0.50 per share payable in the first quarter of 2007. Dividends declared in 2005 were $1.705 which included quarterly dividends of $0.4125 per share paid in the second and third quarters of 2005, a quarterly dividend of $0.43 per share paid in the fourth quarter of 2005 and a quarterly dividend of $0.45 per share paid in the first quarter of 2006. The amount and timing of all dividend declarations are subject to the discretion of the Board and its consideration of business conditions, results of operations, financial condition and other factors.

(B) PREFERRED AND PREFERENCE STOCK-

FirstEnergy has 5 million authorized shares of $100 par value preferred stock and OE has 8 million authorized shares of $25 par value preferred stock. CEI’s, Met-Ed's and Penelec's preferred stock authorizations consist of 4 million, 10 million and 11.435 million shares, respectively, without par value. No preferred shares were outstanding for those companies as of December 31, 2006 or 2005.

The Companies' preference stock authorization consists of 8 million shares without par value for OE; 3 million shares without par value for CEI; and 5 million shares, $25 par value for TE. No preference shares are currently outstanding.

(C)

LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS-

Subordinated Debentures to Affiliated Trusts

As of December 31, 2006, CEI's wholly owned statutory business trust, Cleveland Electric Financing Trust, had $100 million of outstanding 9.00% preferred securities that mature in 2031. The sole assets of the trust are CEI's subordinated debentures having the same rate and maturity date as the preferred securities.

CEI formed the trust to sell preferred securities and invested the gross proceeds in the 9.00% subordinated debentures of CEI. The sole assets of the trust are the applicable subordinated debentures. Interest payment provisions of the subordinated debentures match the distribution payment provisions of the trust's preferred securities. In addition, upon redemption or payment at maturity of subordinated debentures, the trust's preferred securities will be redeemed on a pro rata basis at their liquidation value. Under certain circumstances, the applicable subordinated debentures could be distributed to the holders of the outstanding preferred securities of the trust in the event that the trust is liquidated. CEI has effectively provided a full and unconditional guarantee of payments due on the trust's preferred securities. The trust's preferred securities were redeemable at 100% of their principal amount at CEI's option beginning in December 2006. Interest on the subordinated debentures (and therefore distributions on the trust's preferred securities) may be deferred for up to 60 months, but CEI may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred payments on its subordinated debentures are paid in full.

Securitized Transition Bonds

The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. In June 2002, JCP&L Transition Funding sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold $182 million of transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS.

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's Consolidated Balance Sheet. As of December 31, 2006, $429 million of transition bonds are 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 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. FirstEnergy and its subsidiaries have various debt covenants under their respective financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt and the maintenance of certain financial ratios. There also exist cross-default provisions among financing arrangements of FirstEnergy and the Companies.

Based on the amount of FMB authenticated by the respective mortgage bond trustees through December 31, 2006, the Companies' annual sinking fund requirement for all FMB issued under the various mortgage indentures amounts to $104 million. OE and Penn expect to deposit funds with their respective mortgage bond trustees in 2007 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 increases in the amount of the annual sinking fund requirement. JCP&L, Met-Ed and Penelec could fulfill their sinking fund obligations by providing bondable property additions, previously retired FMB or cash to the respective mortgage bond trustees.

Sinking fund requirements for FMB and maturing long-term debt (excluding capital leases) for the next five years are:

	*(In millions)*
2007	$	1,867
2008		418
2009		287
2010		214
2011		1,540

Included in the table above are amounts for certain variable interest rate pollution control revenue bonds that have provisions by which individual debt holders are required to "put back" the respective debt to the issuer for redemption prior to its maturity date. These amounts are $1.6 billion, $82 million and $15 million in 2006, 2008 and 2010, respectively, representing the next time the debt holders may exercise this provision.

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, 2006 or noncancelable municipal bond insurance policies of $343 million at December 31, 2006 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 0.55% to 1.70% of the amounts of the LOCs to the issuing banks and 0.16% to 0.38% of the amounts of the 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.

Certain secured notes of CEI and TE are entitled to the benefit of noncancelable municipal bond insurance policies of $120 million and $30 million, respectively, to pay principal of, or interest on, the applicable notes. To the extent that drawings are made under the policies, CEI and TE are entitled to a credit against their obligation to repay those notes. CEI and TE are obligated to reimburse the insurer for any drawings thereunder.

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 the replacement LOCs and the issuer of the standby LOC obtained the right to pledge or assign participations in OE's reimbursement obligations 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.

12.

ASSET RETIREMENT OBLIGATIONS-

FirstEnergy has recognized applicable legal obligations under SFAS 143 for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, FirstEnergy has recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47, which was implemented on December 31, 2005.

The ARO liability of $1.19 billion as of December 31, 2006 primarily relates to the nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. The obligation to decommission these units was developed based on site specific studies performed by an independent engineer. FirstEnergy uses an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

In 2006, FirstEnergy 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 FirstEnergy’s sludge disposal pond located near the 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.

In 2005, FirstEnergy revised the ARO associated with Beaver Valley Units 1 and 2, Davis-Besse and Perry, as a result of updated decommissioning studies. The present value of revisions in the estimated cash flows associated with projected decommissioning costs increased the ARO for Beaver Valley Unit 1 by $21 million and decreased the ARO for Beaver Valley Unit 2 by $22 million, resulting in a net decrease in the ARO liability and corresponding plant asset of $1 million. The present value of revisions in the estimated cash flows associated with projected decommissioning costs decreased the ARO and corresponding plant asset for Davis-Besse and Perry by $21 million and $57 million, respectively.

FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2006, the fair value of the decommissioning trust assets was approximately $2.0 billion.

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 it 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.

FirstEnergy identified applicable legal obligations as defined under the new standard at its active and retired generating units, 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, FirstEnergy recorded a conditional ARO liability of $57 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $16 million (recorded as part of the carrying amount of the related long-lived asset) and accumulated depreciation of $12 million. FirstEnergy charged a regulatory liability of $5 million upon adoption of FIN 47 for the transition amounts related to establishing the ARO for asbestos removal from substation control rooms and service center buildings for OE, Penn, CEI, TE and JCP&L. The remaining cumulative effect adjustment for unrecognized depreciation and accretion of $48 million was charged to income ($30 million, net of tax), -- $0.09 per share of common stock (basic and diluted) for the year ended December 31, 2005.

The following table describes the changes to the ARO balances during 2006 and 2005.

	2006			2005
ARO Reconciliation	*(In millions)*
Balance at beginning of year	$ 1,126			$ 1,078
Liabilities incurred		-			-
Liabilities settled		(6	)		-
Accretion		72			70
Revisions in estimated cash flows		(2	)		(79	)
FIN 47 ARO upon adoption		-			57
Balance at end of year	$	1,190		$	1,126

The following table provides the December 31, 2005 balance of the conditional ARO as if FIN 47 had been adopted on January 1, 2005:

Adjusted ARO Reconciliation	2005
	*(In millions)*
Beginning balance as of January 1, 2005	$	54
Accretion		3
Ending balance as of December 31, 2005	$	57

The effect on income as if FIN 47 had been applied during 2004 was immaterial.

13. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT

FirstEnergy had approximately $1.1 billion of short-term indebtedness as of December 31, 2006, comprised of $1.0 billion in borrowings under a $2.75 billion revolving line of credit and $103 million of other bank borrowings. Total short-term bank lines of committed credit to FirstEnergy and the Companies as of December 31, 2006 were approximately $3.4 billion.

On August 24, 2006, FirstEnergy and certain of its subsidiaries, as borrowers, entered into a new $2.75 billion five-year revolving credit facility, which replaced FirstEnergy’s prior $2 billion credit facility. FirstEnergy may request an increase in the total commitments available under the new facility up to a maximum of $3.25 billion. Commitments under the new facility are available until August 24, 2011, unless the lenders agree, at the request of the Borrowers, to two 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. As of December 31, 2006, FirstEnergy was the only borrower on this revolver. The annual facility fee is 0.125%.

The Companies, with the exception of TE and JCP&L, each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company. The receivables financing borrowing capacity by company are shown in the following table. There were no outstanding borrowings as of December 31, 2006.

Subsidiary Company	Parent Company		Capacity		Annual Facility Fee
	*(In millions)*
OES 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 as of December 31, 2006 and 2005 were 5.71% and 4.68%, respectively. The annual facility fees on all current committed short-term bank lines of credit range from 0.125% to 0.15%.

14. COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A) NUCLEAR INSURANCE-

The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.8 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. FirstEnergy's maximum potential assessment under the industry retrospective rating plan would be $402 million per incident but not more than $60 million in any one year for each incident.

FirstEnergy is also insured under policies for each nuclear plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination costs. FirstEnergy has also obtained approximately $2.0 billion of insurance coverage for replacement power costs. Under these policies, FirstEnergy can be assessed a maximum of approximately $72 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.

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, repair and replacement costs and other such costs arising from a nuclear incident at any of 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 FirstEnergy's insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs.

(B) GUARANTEES AND OTHER ASSURANCES-

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of December 31, 2006, outstanding guarantees and other assurances aggregated approximately $5.4 billion -contract guarantees $2.5 billion, surety bonds $0.1 billion and LOCs $2.8 billion.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for subsidiary financings or refinancings of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $1.0 billion (included in the $2.5 billion discussed above) as of December 31, 2006 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating-downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of December 31, 2006, FirstEnergy's maximum exposure under these collateral provisions was $468 million.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $130 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions.

FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($27 million as of December 31, 2006), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

(C) ACCELERATED SHARE REPURCHASE PROGRAM-

On August 9, 2006, FirstEnergy entered into an accelerated share repurchase agreement with a financial institution counterparty under which FirstEnergy repurchased 10.6 million shares, or approximately 3.2%, of its outstanding common stock on August 10, 2006 at an initial price of $56.44 per share, or a total initial purchase price of $600 million. This forward sale contract is being accounted for as an equity instrument. The final purchase price is subject to a contingent purchase price adjustment based on the average of the daily volume-weighted average prices over a subsequent purchase period of up to seven months, as well as other purchase price adjustments in the event of an extraordinary cash dividend or other dilution events. The price adjustment can be settled, at FirstEnergy’s option, in cash or in shares of its common stock. The size of any settlement amount and whether it is to be paid or received by FirstEnergy will depend upon the average of the daily volume-weighted average prices of the shares as calculated by the counterparty under the program. The settlement is expected to occur in the first quarter of 2007.

The accelerated share repurchase was completed under a program authorized by the Board of Directors on June 20, 2006 to repurchase up to 12 million shares of common stock. At management’s discretion, additional shares may be acquired under the program on the open market or through privately negotiated transactions, subject to market conditions and other factors. The Board’s authorization of the repurchase program does not require FirstEnergy to make any further repurchases of shares and the program may be terminated at any time. On January 30, 2007, FirstEnergy’s Board of Directors authorized a new share repurchase program for up to 16 million shares, or approximately 5% of FirstEnergy’s outstanding common stock. This new program supplements the prior repurchase program approved on June 20, 2006, such that up to 26.6 million potential shares may ultimately be repurchased under the combined plans . At management’s discretion, shares may be acquired on the open market or through privately negotiated transactions, subject to market conditions and other factors. FirstEnergy is currently in negotiations with a major financial institution to enter into a new accelerated share repurchase program contingent among other things on amending its current accelerated share repurchase program to allow FirstEnergy to enter into the new accelerated repurchase program.

(D) ENVIRONMENTAL MATTERS-

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in compliance with existing regulations but is unable to predict future changes in regulatory policies and what, if any, the effects of such changes would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $1.8 billion for 2007 through 2011.

FirstEnergy accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

Clean Air Act Compliance

FirstEnergy is required to meet federally-approved SO ₂ emissions regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO ₂ regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

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. FirstEnergy has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided 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.

FirstEnergy complies with SO ₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO _X reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NO _X reductions at FirstEnergy's facilities. The EPA's NO _X Transport Rule imposes uniform reductions of NO _X emissions (an approximate 85% reduction in utility plant NO _X emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NO _X emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NO _X budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. 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 provided each affected state until 2006 to develop implementing regulations to achieve additional reductions of NO _X and SO ₂ emissions in two phases (Phase I in 2009 for NO _X , 2010 for SO ₂ and Phase II in 2015 for both NO _X and SO ₂ ). FirstEnergy's Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to caps on SO ₂ and NO _X emissions, whereas its New Jersey fossil-fired generation facility will be subject to only a cap on 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, capping SO ₂ emissions in affected states to just 2.5 million tons annually. NO _X 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 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. 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, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO ₂ and NO _X emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FirstEnergy would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FirstEnergy will be disadvantaged if these model rules were implemented as proposed because FirstEnergy’s substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

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. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. The future cost of compliance with these regulations, if approved and implemented, may be substantial.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as the New Source Review cases.

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the New Source Review litigation. This settlement agreement, which is in the form of a consent decree, was approved by the Court on July 11, 2005, and requires reductions of NO _X and SO ₂ emissions at the W. H. Sammis Plant and other FES coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation are currently estimated to be $1.5 billion ($400 million of which is expected to be spent in 2007, with the largest portion of the remaining $1.1 billion expected to be spent in 2008 and 2009).

The Sammis NSR Litigation consent decree also requires us 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 under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of SO ₂ emissions. FGCO also entered into an agreement with B&W on August 25, 2006 to supply flue gas desulfurization systems for the reduction of SO ₂ emissions. Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions also are being installed at the W.H. Sammis Plant under a 1999 agreement with B&W.

OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties paid by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities in the first quarter of 2005 of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18% through 2012. 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.

FirstEnergy cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO ₂ emissions could require significant capital and other expenditures. The CO ₂ emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO ₂ emitting gas-fired and nuclear generators.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. On January 26, 2007, the federal Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to EPA for further rulemaking and eliminated the restoration option from EPA’s regulations. FirstEnergy is conducting comprehensive demonstration studies, due in 2008, to determine the operational measures or equipment, if any, necessary for compliance by its facilities with the performance standards. FirstEnergy is unable to predict the outcome of such studies or changes in these requirements from the remand to EPA. Depending on the outcome of such studies and EPA’s further rulemaking, the future cost of compliance with these standards may require material capital expenditures.

Regulation of Hazardous Waste

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of December 31, 2006, FirstEnergy had approximately $1.4 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry. As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans to seek for these facilities.

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2006, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $88 million have been accrued through December 31, 2006.

(E)

OTHER LEGAL PROCEEDINGS-

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision on July 8, 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, New Jersey. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Because it effectively terminates this class action, plaintiffs appealed this ruling to the New Jersey Appellate Division, where the matter is currently pending. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of December 31, 2006.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s 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 proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

FirstEnergy companies also are defending five separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Three other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these three cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc., as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. On March 7, 2006, the PUCO issued a ruling, consolidating all of the pending outage cases for hearing; limiting the litigation to service-related claims by customers of the Ohio operating companies; dismissing FirstEnergy as a defendant; and ruling that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on October 16, 2007.

On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid to numerous insureds who allegedly suffered losses as a result of the August 14, 2003 outages. All of the insureds appear to be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006. On January 18, 2007, the Court granted the Companies’ motion to dismiss the case. It is unknown whether or not the matter will be further appealed. No estimate of potential liability is available for any of these cases.

FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy were based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. The plaintiff has not appealed.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although FirstEnergy is unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Nuclear Plant Matters

On January 20, 2006, FENOC announced that it had entered into a deferred prosecution agreement with the U.S. Attorney’s Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the DOJ related to FENOC’s communications with the NRC during the fall of 2001 in connection with the reactor head issue at the Davis-Besse Nuclear Power Station. Under the agreement, the United States acknowledged FENOC’s extensive corrective actions at Davis-Besse, FENOC’s cooperation during investigations by the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related criminal and administrative investigations and proceedings, FENOC’s acknowledgement of responsibility for the behavior of its employees, and its agreement to pay a monetary penalty. The DOJ agreed to refrain from seeking an indictment or otherwise initiating criminal prosecution of FENOC for all conduct related to the statement of facts attached to the deferred prosecution agreement, as long as FENOC remained in compliance with the agreement, which FENOC has done. FENOC paid a monetary penalty of $28 million (not deductible for income tax purposes) which reduced FirstEnergy's earnings by $0.09 per common share in the fourth quarter of 2005. The deferred prosecution agreement expired on December 31, 2006.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue discussed above. FirstEnergy accrued $2 million for a potential fine prior to 2005 and accrued the remaining liability for the proposed fine during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005. On January 23, 2006, FENOC supplemented its response to the NRC's NOV on the Davis-Besse head degradation to reflect the deferred prosecution agreement that FENOC had reached with the DOJ.

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Nuclear Power Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Nuclear Power Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's 2005 annual assessment letter dated March 2, 2006 and associated meetings to discuss the performance of the Perry Nuclear Power Plant on March 14, 2006, the NRC again stated that the Perry Nuclear Power Plant continued to operate in a manner that "preserved public health and safety." However, the NRC also stated that increased levels of regulatory oversight would continue until sustained improvement in the performance of the facility was realized. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. Although FirstEnergy is unable to predict the impact of the ultimate disposition of this matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the now repealed PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005, additional information was requested regarding Davis-Besse-related disclosures, which has been provided. FirstEnergy has cooperated fully with the informal inquiry and continues to do so with the formal investigation.

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On October 18, 2006, the Ohio Supreme Court transferred this case to a Tuscarawas County Common Pleas Court judge due to concerns over potential class membership by the Jefferson County Common Pleas Court.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. JCP&L intends to re-file an appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

15. FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS

In 2005, the Ohio Companies and Penn entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred do not include leasehold interests of CEI, TE and OE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, the Ohio Companies and Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.

On December 16, 2005, the Ohio Companies and Penn completed the intra-system transfer of their respective ownership in the nuclear generation assets to NGC through, in the case of OE and Penn, an asset spin-off in the form of a dividend and, in the case of CEI and TE, a sale at net book value.

On December 28, 2006, the NRC approved the transfer of ownership in NGC 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.

These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer 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 our consolidated results.

16. SEGMENT INFORMATION

FirstEnergy has two reportable operating segments: regulated services and power supply management services. None of the aggregate “Other” segments individually meet the criteria to be considered a reportable segment. The regulated services segment consists of the regulated sale of electricity and distribution and transmission services by FirstEnergy’s eight utility subsidiaries in Ohio, Pennsylvania and New Jersey. The power supply management services segment primarily consists of the subsidiaries (FES, FGCO, NGC and FENOC) that sell electricity in deregulated markets and operate and own generation facilities. “Other” consists of telecommunications services and the recently sold MYR (a construction service company) and retail natural gas operations (see Note 8). The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”

The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems. Its revenues are primarily derived from the delivery of electricity and transition cost recovery. Assets of the regulated services segment as of December 31, 2004 included generating units that were leased or whose output had been sold to the power supply management services segment (see Note 15). The regulated services segment’s internal revenues in 2005 and 2004 represented the rental revenues for the generating unit leases which ceased in the fourth quarter of 2005 as a result of the intra-system asset transfers (see Note 15).

The power supply management services segment supplies the electric power needs of FirstEnergy’s end-use customers through retail and wholesale arrangements, including regulated retail sales to meet all or a portion of the PLR requirements of its Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns and operates FirstEnergy’s generating facilities and purchases electricity to meet sales obligations (see Note 15). The segment's net income is primarily derived from all electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission, congestion and ancillary costs charged by PJM and MISO to deliver energy to retail customers.

Segment reporting in 2005 and 2004 has been revised to conform to the current year business segment organization and operations and the reclassification of discontinued operations sold in 2006 (See Note 2(J)). Changes in the current year operations reporting reflected in the revised 2005 and 2004 segment reporting primarily includes the transfer of retail transmission revenues and PJM/MISO transmission revenues and expenses associated with serving electricity load previously included in the regulated services segment to the power supply management services segment. In addition, as a result of the 2005 Ohio tax legislation reducing the effective state income tax rate, the calculated composite income tax rates used in the two reportable segments’ results have been changed to 40% from the tax rates previously reported in their 2005 and 2004 segment results. The net amounts of the changes in the 2005 and 2004 reportable segments' income taxes reclassifications have been correspondingly offset in the respective year’s "Reconciling Adjustments” results. FSG, which had been classified as held for sale as of December 31, 2005 (See Note 2(J)), completed the sale of its five remaining subsidiaries in 2006. Its assets and results for 2006, 2005 and 2004 are combined in the “Other” segments in this report, as the remaining business does not meet the criteria of a reportable segment. Interest expense on holding company debt and corporate support services revenues and expenses are included in "Reconciling Items."

100


				Power
				Supply
	Regulated			Management						Reconciling
Segment Financial Information	Services			Services			Other			Adjustments			Consolidated
	(In millions)
2006
External revenues	$	4,441		$	7,029		$	103		$	(72	)	$	11,501
Internal revenues		-			-			-			-			-
Total revenues		4,441			7,029			103			(72	)		11,501
Depreciation and amortization		1,001			(70	)		4			22			957
Investment income		270			36			1			(158	)		149
Net interest charges		410			215			6			71			702
Income taxes		632			310			(20	)		(127	)		795
Income from continuing operations		932			465			44			(183	)		1,258
Discontinued operations		-			-			(4	)		-			(4	)
Net income		932			465			40			(183	)		1,254
Total assets		23,336			6,976			297			587			31,196
Total goodwill		5,873			24			1			-			5,898
Property additions		633			644			1			37			1,315

2005
External revenues	$	5,155		$	6,067		$	115		$	21		$	11,358
Internal revenues		270			-			-			(270	)		-
Total revenues		5,425			6,067			115			(249	)		11,358
Depreciation and amortization		1,483			(46	)		2			25			1,464
Investment income		217			-			-			-			217
Net interest charges		389			54			6			207			656
Income taxes		784			(28	)		12			(19	)		749
Income (loss) from continuing operations		1,174			(41	)		14			(268	)		879
Discontinued operations		-			-			12			-			12
Cumulative effect of accounting change		(21	)		(9	)		-			-			(30	)
Net income (loss)		1,153			(50	)		26			(268	)		861
Total assets		23,975			6,556			605			705			31,841
Total goodwill		5,932			24			54			-			6,010
Property additions		788			375			8			37			1,208

2004
External revenues	$	4,885		$	6,510		$	201		$	4		$	11,600
Internal revenues		318			-			-			(318	)		-
Total revenues		5,203			6,510			201			(314	)		11,600
Depreciation and amortization		1,422			35			3			34			1,494
Investment income		205			-			-			-			205
Net interest charges		363			37			15			251			666
Income taxes		698			75			(24	)		(68	)		681
Income from continuing operations		1,047			112			38			(290	)		907
Discontinued operations		-			-			(29	)		-			(29	)
Net income		1,047			112			9			(290	)		878
Total assets		28,308			1,488			760			479			31,035
Total goodwill		5,951			24			75			-			6,050
Property additions		572			246			7			21			846

Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses, fuel marketing revenues (which are reflected as reductions to expenses for internal management reporting purposes) and elimination of intersegment transactions.

101

Products and Services*

			Energy Related
	Electricity		Sales and
Year	Sales		Services
2006	$	10,671	$	48
2005		10,546		77
2004		10,831		91

* See Note 2(J) for discussion of discontinued operations.

17.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

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 liabilities at fair value. The Standard requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the 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, Fair Value Measurements, and SFAS 107, Disclosures about Fair Value of Financial Instruments. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

FSP EITF 00-19-2 - “Accounting for Registration Payment Arrangements”

In December 2006, the FASB issued FSP EITF 00-19-2, which addresses an issuer’s accounting for registration payment arrangements. This guidance specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with SFAS 5, Accounting for Contingencies. This FSP shall be effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of issuance of this FSP. For arrangements that were entered into prior to the issuance of this FSP, this guidance shall be effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years. FirstEnergy does not expect this FSP to have a material effect on its financial statements.

EITF 06-5 - “Accounting for Purchases of Life Insurance-Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance”

In September 2006, the EITF reached a consensus on Issue 06-5 concluding that a policyholder should consider any additional amounts included in the contractual terms of the policy in determining the amount that could be realized under the insurance contract. Contractual limitations should be considered when determining the realizable amounts. Amounts that are recoverable by the policyholder at the discretion of the insurance company should be excluded from the amount that could be realized. Recoverable amounts in periods beyond one year from the surrender of the policy should be discounted in accordance with APB Opinion No. 21, “Interest on Receivables and Payables.” Consensus was also reached that a policyholder should determine the amount that could be realized under the insurance contract assuming the surrender of an individual-life by individual-life policy (or certificate by certificate in a group policy). Any amount that would ultimately be realized by the policyholder upon the assumed surrender of the final policy (or final certificate) should be included in the amount that could be realized under the insurance contract. The EITF also concluded that a policyholder should not discount the cash surrender value component of the amount that could be realized when contractual restrictions on the ability to surrender a policy exist. However, if the contractual limitations prescribe that the cash surrender value component of the amount that could be realized is a fixed amount, then the amount that could be realized should be discounted in accordance with APB Opinion No. 21. This Issue is effective for fiscal years beginning after December 15, 2006. FirstEnergy does not expect this EITF to have a material impact on its financial statements.

SFAS 157 - “Fair Value Measurements”

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 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

102

FSP FIN 46(R)-6 - “Determining the Variability to Be Considered in Applying FASB interpretation No. 46(R)”

In April 2006, the FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should determine the variability to be considered in applying FASB interpretation No. 46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the first quarter of 2004, consolidating VIEs when FirstEnergy or one of its subsidiaries is determined to be the VIE’s primary beneficiary. The variability that is considered in applying interpretation 46(R) affects the determination of (a) whether the entity is a VIE; (b) which interests are variable interests in the entity; and (c) which party, if any, is the primary beneficiary of the VIE. This FSP states that the variability to be considered shall be based on an analysis of the design of the entity, involving two steps:

Step 1:	Analyze the nature of the risks in the entity
Step 2:	Determine the purpose(s) for which the entity was created and determine the variability the entity is designed to create and pass along to its interest holders.

After determining the variability to consider, the reporting enterprise can determine which interests are designed to absorb that variability. The guidance in this FSP is applied prospectively to all entities (including newly created entities) with which that enterprise first becomes involved and to all entities previously required to be analyzed under interpretation 46(R) when a reconsideration event has occurred after July 1, 2006. FirstEnergy does not expect this Statement to have a material impact on its financial statements.

FIN 48 - “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109”

In June 2006, the FASB issued FIN 48 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation will be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit to recognize in the financial statements. This interpretation is effective for fiscal years beginning after December 15, 2006. FirstEnergy is currently evaluating the impact of this Statement. The Company does not expect this Statement to have a material impact on its financial statements.

103

18. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)

The following summarizes certain consolidated operating results by quarter for 2006 and 2005. Certain financial results have been reclassified to discontinued operations from amounts previously reported due to the divestiture of certain non-core businesses in 2006 as discussed in Note 2(J).

	March 31,		June 30,			September 30,		December 31,
Three Months Ended	2006		2006			2006		2006
	*(In millions, except per share amounts)*
Revenues	$	2,705	$	2,751		$	3,365	$	2,680
Expenses		2,233		2,081			2,505		2,076
Operating Income		472		670			860		604
Other Expense		117		142			134		160
Income From Continuing Operations Before Income Taxes		355		528			726		444
Income Taxes		136		216			274		170
Income From Continuing Operations		219		312			452		274
Discontinued Operations
(Net of Income Taxes) (Note 2(J))		2		(8	)		2		-
Net Income	$	221	$	304		$	454	$	274

Basic Earnings Per Share of Common Stock:
Income From Continuing Operations	$	0.67	$	0.94		$	1.41	$	0.85
Discontinued Operations		-		(0.02	)		-		-
Net Earnings Per Basic Share	$	0.67	$	0.92		$	1.41	$	0.85

Diluted Earnings Per Share of Common Stock:
Income From Continuing Operations	$	0.67	$	0.93		$	1.40	$	0.84
Discontinued Operations		-		(0.02	)		-		-
Net Earnings Per Diluted Share	$	0.67	$	0.91		$	1.40	$	0.84

	March 31,		June 30,			September 30,		December 31,
Three Months Ended	2005		2005			2005		2005
	*(In millions, except per shar amounts)*
Revenues	$	2,627	$	2,678		$	3,333	$	2,721
Expenses		2,234		2,146			2,692		2,220
Operating Income		393		532			641		501
Other Expense		129		114			75		122
Income From Continuing Operations Before Income Taxes		264		418			566		379
Income Taxes		122		238			236		153
Income From Continuing Operations		142		180			330		226
Discontinued Operations
(Net of Income Taxes) (Note 2(J))		18		(2	)		2		(6	)
Cumulative Effect of a Change in Accounting Principle
(Net of Income Taxes) (Note 2(K))		-		-			-		(30	)
Net Income	$	160	$	178		$	332	$	190

Basic Earnings Per Share of Common Stock:
Income From Continuing Operations	$	0.43	$	0.55		$	1.00	$	0.69
Discontinued Operations (Note 2(J))		0.06		(0.01	)		0.01		(0.02	)
Cumulative Effect of a Change in Accounting Principle		-		-			-		(0.09	)
Net Earnings Per Basic Share	$	0.49	$	0.54		$	1.01	$	0.58

Diluted Earnings Per Share of Common Stock:
Income From Continuing Operations	$	0.43	$	0.55		$	1.00	$	0.69
Discontinued Operations		0.05		(0.01	)		0.01		(0.02	)
Cumulative Effect of a Change in Accounting Principle		-		-			-		(0.09	)
Net Earnings Per Diluted Share	$	0.48	$	0.54		$	1.01	$	0.58

Results for the fourth quarter of 2005 included a $30 million after-tax ($0.09 per share) cumulative effect adjustment associated with the adoption of FIN 47 (see Note 12), a $9 million (with no corresponding tax impact) ($0.03 per share) non-cash charge for impairment of goodwill of MYR as required by SFAS 142 (see Note 2(H)) and a $28 million (which is not deductible for income tax purposes) ($0.09 per share) charge related to the Davis-Besse DOJ and NRC fines (see Note 14). Net income for that quarter also included a $15 million after-tax ($0.05 per share) charge relating to prior periods as a result of a JCP&L tax audit adjustment applicable to prior quarters in 2005 and prior years. Management concluded that the adjustment was not material to FirstEnergy's reported consolidated results of operations for any quarter of 2005, nor was it material to the consolidated balance sheets and consolidated cash flows for any of those quarters.

104

OHIO EDISON COMPANY

2006 ANNUAL REPORT TO STOCKHOLDERS

Ohio Edison Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. Ohio Edison engages in the distribution and sale of electric energy to communities in an area of 7,000 square miles in central and northeastern Ohio and, through its wholly owned Pennsylvania Power Company subsidiary, 1,100 square miles in western Pennsylvania. The areas Ohio Edison and Pennsylvania Power serve have populations of approximately 2.8 million and 0.3 million, respectively.

Contents	Page

Glossary of Terms	i-ii
Report of Independent Registered Public Accounting Firm	1
Selected Financial Data	2
Management's Discussion and Analysis	3-20
Consolidated Statements of Income	21
Consolidated Balance Sheets	22
Consolidated Statements of Capitalization	23-24
Consolidated Statements of Common Stockholder's Equity	25
Consolidated Statements of Preferred Stock	25
Consolidated Statements of Cash Flows	26
Consolidated Statements of Taxes	27
Notes to Consolidated Financial Statements	28-49

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify Ohio Edison Company and its affiliates:

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an affiliated Ohio electric utility
Companies	OE and Penn
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
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., a public utility holding company
JCP&L	Jersey Central Power & Light Company, an affiliated New Jersey electric utility
Met-Ed	Metropolitan Edison Company, an affiliated Pennsylvania electric utility
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, an affiliated Pennsylvania electric utility
Penn	Pennsylvania Power Company, OE?s wholly owned Pennsylvania electric utility subsidiary
TE	The Toledo Edison Company, an affiliated Ohio electric utility

The following abbreviations and acronyms are used to identify frequently used terms in this report:

AOCI	Accumulated Other Comprehensive Income
AOCL	Accumulated Other Comprehensive Loss
ARO	Asset Retirement Obligation
B&W	Babcock & Wilcox Company
Bechtel	Bechtel Power Corporation
CAT	Commercial Activity Tax
CBP	Competitive Bid Process
DOJ	United States Department of Justice
ECAR	East Central Area Reliability Coordination Agreement
EPA	U. S. Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ERO	Electric Reliability Organization
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 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?
Fitch	Fitch Ratings, Ltd.
FMB	First Mortgage Bonds
FSP	FASB Staff Position
FSP SFAS 115-1 and SFAS 124-1	FASB Staff Position No. 115-1 and SFAS 124-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
GAAP	Accounting Principles Generally Accepted in the United States
KWH	Kilowatt-hours
LOC	Letter of Credit
MISO	Midwest Independent Transmission System Operator, Inc.
Moody?s	Moody?s Investors Service
MSG	Market Support Generation
MW	Megawatts
NERC	North American Electric Reliability Corporation
NOx	Nitrogen Oxide
NOPR	Notice of Proposed Rulemaking
NOV	Notice of Violation
OCC	Office of the Ohio Consumers' Counsel
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
PJM	PJM Interconnection LLC
PLR	Provider of Last Resort

GLOSSARY OF TERMS, Cont'd.

PPUC	Pennsylvania Public Utility Commission
PSA	Power Supply Agreements
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
S&P	Standard & Poor's Ratings Service
SCR	Selective Catalytic Reduction
SEC	United States Securities and Exchange Commission
SFAC	Statement of Financial Accounting Concepts
SFAC 7	SFAC No.. 7, "Using Cash Flow Information and Present Value in Accounting Measurements"
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS No.. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 87	SFAS No.. 87, "Employers' Accounting for Pensions"
SFAS 101	SFAS No.. 101, ?Accounting for Discontinuation of Application of SFAS 71?
SFAS 106	SFAS No.. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
SFAS 107	SFAS No.. 107, ?Disclosures about Fair Value of Financial Instruments?
SFAS 115	SFAS No.. 115, "Accounting for Certain Investments in Debt and Equity Securities"
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 Statements No. 115?
SO ₂	Sulfur Dioxide
VIE ⁽²⁾	Variable Interest Entity

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Ohio Edison Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder?s equity, preferred stock and cash flows present fairly, in all material respects, the financial position of Ohio Edison Company and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company?s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

Our audit was conducted for the purpose of forming an opinion on the basic financial statements taken as a whole. The Supplemental Consolidated Statements of Taxes is presented for purposes of additional analysis and is not a required part of the basic financial statements. Such information has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole.

As discussed in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit pension and other postretirement benefit plans as of December 31, 2006. As discussed in Note 2(G) and Note 11 to the consolidated financial statements, the Company changed its method of accounting for conditional asset retirement obligations as of December 31, 2005 .

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 27, 2007

The following selected financial data should be read in conjunction with, and is qualified in its entirety by reference to, the sections entitled ?Management?s Discussion and Analysis of Results of Operations and Financial Condition? and with our consolidated financial statements and the ?Notes to Consolidated Financial Statements.? Our Consolidated Statements of Income are not necessarily indicative of future conditions or results of operations.

OHIO EDISON COMPANY

SELECTED FINANCIAL DATA

For the Years Ended December 31,	2006			2005			2004			2003			2002
	*(Dollars in thousands)*

GENERAL FINANCIAL INFORMATION:

Operating Revenues	$	2,427,456		$	2,975,553		$	2,945,583		$	2,925,310		$	2,948,675

Operating Income	$	291,132		$	632,543		$	592,643		$	336,936		$	453,831

Income Before Cumulative Effect
of Accounting Changes	$	211,639		$	330,398		$	342,766		$	292,925		$	356,159

Net Income	$	211,639		$	314,055		$	342,766		$	324,645		$	356,159

Earnings on Common Stock	$	207,087		$	311,420		$	340,264		$	321,913		$	349,649

Total Assets	$	5,120,614		$	6,097,277		$	6,482,627		$	7,316,489		$	7,789,539


CAPITALIZATION AS OF DECEMBER 31:
Common Stockholder?s Equity	$	1,972,385		$	2,502,191		$	2,493,809		$	2,582,970		$	2,839,255
Preferred Stock-
Not Subject to Mandatory Redemption		-			75,070			100,070			100,070			100,070
Subject to Mandatory Redemption		-			-			-			-			13,500
Long-Term Debt and Other Long-Term Obligations		1,118,576			1,019,642			1,114,914			1,179,789			1,219,347
Total Capitalization	$	3,090,961		$	3,596,903		$	3,708,793		$	3,862,829		$	4,172,172


CAPITALIZATION RATIOS:
Common Stockholder?s Equity		63.8	%		69.6	%		67.2	%		66.9	%		68.1	%
Preferred Stock-
Not Subject to Mandatory Redemption		-			2.1			2.7			2.6			2.4
Subject to Mandatory Redemption		-			-			-			-			0.3
Long-Term Debt and Other Long-Term Obligations		36.2			28.3			30.1			30.5			29.2
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%

DISTRIBUTION KWH DELIVERIES (Millions):
Residential		10,500			10,901			10,180			10,009			10,233
Commercial		8,429			8,566			8,276			8,105			7,994
Industrial		11,018			11,058			10,700			10,658			10,672
Other		152			154			144			160			154
Total		30,099			30,679			29,300			28,932			29,053

CUSTOMERS SERVED:
Residential		1,066,582			1,062,665			1,056,560			1,044,419			1,041,825
Commercial		131,188			130,472			129,017			127,856			119,771
Industrial		1,142			1,152			1,149			1,182			4,500
Other		1,937			1,890			1,751			1,752			1,756
Total		1,200,849			1,196,179			1,188,477			1,175,209			1,167,852


Number of Employees		1,432			1,422			1,370			1,521			1,569

OHIO EDISON COMPANY

MANAGEMENT?S DISCUSSION AND

ANALYSIS OF RESULTS OF OPERATIONS

AND FINANCIAL CONDITION

Forward-Looking Statements: This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms ?anticipate,? ?potential,? ?expect,? ?believe,? ?estimate? and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, the continued ability to collect transition and other charges or to recover increased transmission costs, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), and the legal and regulatory changes resulting from the implementation of the Energy Policy Act of 2005 (including, but not limited to, the repeal of the Public Utility Holding Company Act of 1935), the uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated) or levels of emission reductions related to the Consent Decree resolving the New Source Review litigation, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of governmental investigations and oversight, including by the Securities and Exchange Commission, the Nuclear Regulatory Commission and the various state public utility commissions as disclosed in our Securities and Exchange Commission filings, generally, and heightened scrutiny at the Perry Nuclear Power Plant in particular, the timing and outcome of various proceedings before the Public Utilities Commission of Ohio (including, but not limited to, the successful resolution of the issues remanded to the Public Utilities Commission of Ohio by the Ohio Supreme Court regarding the Rate Stabilization Plan), the continuing availability and operation of generating units, the inability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives), the anticipated benefits from voluntary pension plan contributions, the ability to improve electric commodity margins and to experience growth in the distribution business, the ability to access the public securities and other capital markets and the cost of such capital, the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the August 14, 2003 regional power outage, the risks and other factors discussed from time to time in our Securities and Exchange Commission filings, and other similar factors. Also, a credit rating should not be viewed as a recommendation to buy, sell or hold securities and may be revised or withdrawn by a rating agency at any time. We expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

Reclassifications

As discussed in Note 1 to the consolidated financial statements, certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications did not change previously reported earnings for 2005 and 2004. All reclassifications have been evaluated and determined to be properly reflected as reclassifications in the respective period as presented in the Consolidated Balance Sheets and Statements of Cash Flows.

FirstEnergy Intra-System Generation Asset Transfers

In 2005, the Ohio Companies and Penn entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy?s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred did not include our leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, we completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.

On December 16, 2005, we completed the intra-system transfer of our ownership interests in the nuclear generation assets to NGC through an asset spin-off in the form of a dividend. FENOC continues to operate and maintain the nuclear generation assets.

These transactions were undertaken pursuant to the Ohio Companies? and Penn?s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.

The transfers affect our comparative earnings results with reductions in both revenues and expenses. Revenues are reduced due to the termination of certain arrangements with FES, under which we sold our nuclear-generated KWH to FES and leased our non-nuclear generation assets to FGCO, a subsidiary of FES. Our expenses are lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets. With respect to our retained leasehold interests in the Perry Plant and Beaver Valley Unit 2, we have continued the nuclear-generated KWH sales arrangement with FES for the associated output and continue to be obligated on the applicable portion of expenses related to those interests. In addition, we receive interest income on associated company notes receivable from the transfer of our generation net assets. FES continues to provide our PLR requirements under revised purchased power arrangements covering the three-year period beginning January 1, 2006 (see Outlook - Regulatory Matters).

The effects on our results of operations in 2006 compared to 2005 from the generation asset transfers are summarized in the following table:


Intra-System Generation Asset Transfers			Increase
Income Statement Effects			(Decrease)
			*(In millions)*
Revenues:
Non-nuclear generating units rent	(a	)	$	(146	)
Nuclear-generated KWH sales	(b	)		(290	)
Total - Revenues Effect				(436	)
Expenses:
Fuel costs - nuclear	(c	)		(44	)
Nuclear operating costs	(c	)		(150	)
Provision for depreciation	(d	)		(46	)
General taxes	(e	)		(13	)
Total - Expenses Effect				(253	)
Operating Income Effect				(183	)
Other Income (expense):
Interest income from notes receivable	(f	)		57
Nuclear decommissioning trust earnings	(g	)		(12	)
Interest expense	(h	)		( 7	)
Capitalized interest	(i	)		(9	)
Total - Other Income Effect				43
Income Before Income Taxes Effect				(140	)
Income Taxes	(j	)		(57	)
Net Income Effect			$	(83	)

(a) Elimination of non-nuclear generation assets lease to FGCO.
(b) Reduction of nuclear-generated wholesale KWH sales to FES.
(c) Reduction of nuclear fuel and operating costs.
(d) Reduction of depreciation expense and asset retirement obligation accretion related to generation assets.
(e) Reduction of property tax expense on generation assets.
(f) Interest income on associated company notes receivable from the transfer of generation net assets.
(g) Reduction of earnings on nuclear decommissioning trusts.
(h) Elimination of interest on pollution control notes redeemed in conjunction with the nuclear asset transfer.
(i) Reduction of allowance for borrowed funds used during construction on nuclear capital expenditures.
(j) Income tax effect of the above adjustments.

Results of Operations

Earnings on common stock in 2006 decreased to $207 million from $311 million in 2005. The change in earnings reflected the effects of the generation asset transfer shown in the table above. Excluding the impact of the asset transfer, earnings decreased $21 million primarily due to lower revenues and increased purchased power costs, partially offset by decreased amortization of regulatory assets.

Earnings on common stock in 2005 decreased to $311 million from $340 million in 2004.. Earnings on common stock in 2005 included an after-tax charge to income of $16 million from the cumulative effect of a change in accounting principle due to the adoption of FIN 47 in December 2005 (see Note 2(G)). Income before the cumulative effect of an accounting change was $330 million in 2005. The earnings decrease in 2005 primarily resulted from increases in regulatory asset amortization and other operating costs and a decrease in other income, partially offset by higher revenues and lower purchased power and nuclear operating costs compared to 2004.

Revenues

Revenues decreased by $548 million or 18.4% in 2006 compared with 2005 primarily due to the generation asset transfer impact summarized in the table above. Excluding the effects of the asset transfer, revenues decreased $112 million, primarily due to decreases in wholesale revenues of $247 million and distribution revenues of $449 million, partially offset by an increase in retail generation revenues of $500 million and reduced customer shopping incentives of $82 million.

Revenues increased by $30 million or 1.0% in 2005 compared with 2004 primarily due to increases in retail generation revenues of $50 million and distribution revenues of $43 million, partially offset by decreases of $37 million in wholesale revenues and $32 million in lease revenues from associated companies.

The lower wholesale revenues in 2006 primarily resulted from the termination of a non-affiliated wholesale sales agreement ($203 million) and the December 2005 cessation of the MSG sales arrangements under our transition plan ($56 million). We had been required to provide the MSG to non-affiliated alternative suppliers.

Lower wholesale revenues in 2005 compared to 2004 reflected decreased sales to FES of $61 million, due to reduced nuclear generation available for sale , partially offset by a $24 million increase in sales to non-affiliated customers (including MSG sales) reflecting increased KWH sales (2.7%) and higher unit prices. Revenues from the lease of fossil generation assets to FGCO decreased due to the termination of our lease arrangement in conjunction with the non-nuclear generation asset transfers completed on October 24, 2005.

Changes in electric generation KWH sales and revenues in 2006 and 2005 from the prior year are summarized in the following table.

Changes in Generation KWH Sales	2006			2005
Increase (Decrease)
Electric Generation:
Retail		12.4	%		4.4	%
Wholesale*		(64.7	)%		(5.2	)%
Net Decrease in Generation Sales		(7.6	)%		(0.2	)%

Changes in Generation Revenues	2006				2005
Increase (Decrease)	*(In millions)*
Retail Generation:
Residential		$	188			$20
Commercial			153			9
Industrial			159			21
Total Retail Generation			500			50
Wholesale*			(247	)		(37)
Net Increase in Generation Revenues		$	253			$13

* The 2006 amount excludes impact of generation asset transfers related to nuclear-generated KWH sales.

Increased retail generation revenues for 2006 (as shown in the table above) resulted from higher KWH sales and higher unit prices. The increase in generation KWH sales primarily resulted from decreased customer shopping, as the percentage of generation services provided by alternative suppliers to total sales delivered in our service area decreased by: residential - 10.0 percentage points; commercial - 11.9 percentage points; and industrial - 10.2 percentage points. The decrease in shopping resulted from certain alternative energy suppliers terminating their supply arrangements with our shopping customers in the fourth quarter of 2005. Higher unit prices for generation reflected the rate stabilization charge and the fuel recovery rider, both of which became effective in the first quarter of 2006 under provisions of the RSP and RCP.

Increased retail generation revenues for 2005 (as shown in the table above) reflected the impact of higher KWH sales. The increased generation KWH sales to residential (7.0%) and commercial (4.5%) customers reflected increased air-conditioning loads due to warmer summer weather in 2005, compared to 2004. Increased industrial revenues were primarily due to higher unit prices and an increase in generation KWH sales of 1.9%. Industrial sales were also impacted by increased shopping as generation services provided to industrial customers by alternative suppliers as a percent of total industrial sales delivered in our service area increased by 1.0 percentage point compared to 2004. Commercial customer shopping decreased slightly and residential customer shopping remained relatively unchanged from 2004.

Changes in distribution KWH deliveries and revenues in 2006 and 2005 from the prior year are summarized in the following table.

Changes in Distribution KWH Deliveries	2006			2005
Increase (Decrease)
Distribution Deliveries:
Residential		(3.7	)%		7.1	%
Commercial		(1.6	)%		3.5	%
Industrial		(0.4	)%		3.3	%
Net Change in Distribution Deliveries		(1.9	)%		4.7	%

Changes in Distribution Revenues	2006				2005
Increase (Decrease)	*(In millions)*
Residential		$	(195	)	$	44
Commercial			(136	)		2
Industrial			(118	)		(3	)
Net Change in Distribution Revenues		$	(449	)	$	43

Lower distribution revenues shown in the table above for 2006 primarily reflected lower composite prices and reduced KWH deliveries to residential and commercial customers. The lower unit prices in 2006 resulted from the completion of the generation-related transition cost recovery under our rate restructuring plans in 2005 described above, partially offset by increased transmission rates to recover MISO costs beginning in 2006 (see Outlook - Regulatory Matters). Lower KWH deliveries to residential and commercial customers reflected the impact of milder weather conditions in 2006 compared to 2005.

Distribution revenues increased in 2005 compared with 2004 due to higher distribution deliveries to residential and commercial customers due to warmer summer weather in 2005, partially offset by lower unit prices. Revenues in the industrial sector decreased due to lower unit prices , offsetting an increase due to higher distribution deliveries.

Expenses

Total expenses decreased by $207 million in 2006 and by $10 million in 2005. The change in 2006 was impacted by the effects of the generation asset transfers shown in the table above. Excluding the asset transfer effects in 2006, the following table presents changes from the prior year by expense category:

Expenses - Changes	2006			2005
Increase (Decrease)	*(In millions)*
Fuel costs	$	1		$	(3	)
Purchased power costs		337			(31	)
Nuclear operating costs		(1	)		(38	)
Other operating costs		(26	)		68
Provision for depreciation		11			(14	)
Amortization of regulatory assets		(267	)		46
Deferral of new regulatory assets		(9	)		(51	)
General taxes		-			13
Net change in expenses	$	46		$	(10	)

I ncreased purchased power costs in 2006 reflected higher unit prices associated with our current power supply agreement with FES (see Outlook - Regulatory Matters) , partially offset by a decrease in KWH purchased to meet sales requirements. The decrease in other operating costs during 2006 was primarily due to lower transmission expenses as a result of alternative energy suppliers terminating their supply arrangements with our shopping customers in the fourth quarter of 2005 and lower employee benefit expenses. These decreases in 2006 were partially offset by increases in transmission expenses related to MISO Day 2 operations that began on April 1, 2005.

Excluding the effects of the generation asset transfers, depreciation expense was higher in 2006 primarily as a result of the termination of the PUCO-approved depreciation reserve adjustment program at the end of 2005. The decrease in depreciation expense in 2005 compared to 2004 was attributable to revised estimated service life assumptions for fossil generating plants and a decrease in the depreciation of leased electric plant due to the generation asset transfer.

Lower amortization of regulatory assets in 2006 was due to the completion of the generation-related transition cost amortization under our transition plans, partially offset by the amortization of deferred MISO costs for which recovery began in 2006. The increased deferrals of new regulatory assets in 2006 resulted primarily from the deferral of fuel costs ($58 million) and distribution costs ($74 million) under the RCP, partially offset by lower MISO cost deferrals ($43 million) and the decrease in shopping incentive deferrals ($84 million) which ceased in 2006 under the Ohio transition plan. The deferral of interest on the unamortized shopping incentive balances continues under the RCP (see Outlook - Regulatory Matters).

Purchased power costs decreased in 2005 due to lower unit costs, offsetting an increase in KWH purchased to meet increased retail generation sales requirements. Lower nuclear operating costs in 2005 reflect the effect of lower owned/leased interests in two nuclear plants (Beaver Valley Unit 2 - 55.62% and Perry - 35.24%) with refueling outages in 2005 as compared to Beaver Valley Unit 1 (100% owned) that had a refueling outage in 2004. In addition, nuclear operating costs incurred after the nuclear asset transfers on December 16, 2005 were assumed by NGC. The increase in other operating costs in 2005 compared to 2004 was due to increased transmission expenses related to MISO Day 2 transactions that began on April 1, 2005.

Increases in amortization of regulatory assets in 2005 compared to 2004 resulted from higher amortization of Ohio transition regulatory assets, partially offset by increased cost deferrals of new regulatory assets. The higher deferrals in 2005 compared to 2004 primarily resulted from the PUCO-approved MISO cost deferrals and related interest ($49 million).

General taxes increased by $13 million in 2005 compared to 2004, primarily due to higher property taxes and the effect of higher KWH sales which increased Ohio KWH excise tax and Pennsylvania gross receipts tax. Property taxes increased in 2005 due to the absence of a $6 million Pennsylvania property tax refund recognized in 2004.

Other Income

Other income increased $36 million in 2006 compared to 2005, reflecting the effects of the generation asset transfers in the table above. Excluding the effects of the generation asset transfers, other income decreased by $7 million in 2006 primarily due to an increase in interest expense resulting from our June 2006 issuance of $600 million of long-term debt and costs related to our fourth quarter 2006 pollution control note redemptions. These items were partially offset by the absence of the 2005 civil penalty and environmental liability discussed below.

Other income decreased by $21 million in 2005 compared to 2004 due to a n $8.5 million civil penalty paid to the DOJ and a $10 million liability for environmental projects recognized in connection with the W. H. Sammis Plant settlement (see Outlook - Environmental Matters), partially offset by higher interest income earned on associated company notes receivable. Interest on long-term debt was lower due to the redemption of $124 million of pollution control notes in 2005. We also optionally redeemed $38 million of Penn?s preferred stock in 2005.

Income Taxes

Income taxes decreased $186 million in 2006 compared to 2005. Excluding the effects of the generation asset transfer, income taxes decreased $129 million primarily due to lower taxable income and the absence in 2006 of approximately $32 million of income tax charges from the implementation of Ohio tax legislation changes in the second quarter of 2005.

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? that 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 will be computed consistent with the prior law, except that the tax liability as computed was or will be 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 are not expected to reverse during the five-year phase-in period were written off as of June 30, 2005. The impact on income taxes associated with the required adjustment to net deferred taxes for 2005 was an additional tax expense of approximately $32 million, which was partially offset by the initial phase-out of the Ohio income-based franchise tax, which reduced income taxes by approximately $3 million in 2005.

Cumulative Effect of a Change in Accounting Principle

Results in 2005 include an after-tax charge of $16 million recorded upon the adoption of FIN 47 in December 2005. We identified applicable legal obligations as defined under the new standard at our retired generating units, substation control rooms, service center buildings, line shops and office buildings, identifying asbestos as the primary conditional ARO. We recorded a conditional ARO liability of $27 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $9 million (recorded as part of the carrying amount of the related long-lived asset), and accumulated depreciation of $9 million. W e charged regulatory liabilities for $1 million upon adoption of FIN 47 for the transition amounts related to establishing the ARO for asbestos removal from substation control rooms and service center buildings. The remaining cumulative effect adjustment for unrecognized depreciation and accretion of $26 million was charged to income ($16 million, net of tax) for the year ended December 31, 2005 (see Note 11).

Preferred Stock Dividend Requirements and Redemption Premium

Preferred stock dividend requirements and redemption premium increased by $2 million in 2006 from 2005 principally due to costs associated with optional preferred stock redemptions of $75 million in 2006. As of December 31, 2006, all formerly outstanding preferred stock had been redeemed.

Capital Resources and Liquidity

Our cash requirements in 2006 for operating expenses, construction expenditures, scheduled debt maturities and optional preferred stock redemptions were met with a combination of cash from operations, short-term credit arrangements and funds from the capital markets. During 2007, we expect to meet our contractual obligations primarily with cash from operations. Borrowing capacity under our credit facilities is available to manage our working capital requirements. In subsequent years, we expect to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of December 31, 2006, our cash and cash equivalents of approximately $1 million remained unchanged from December 31, 2005.

Cash Flows From Operating Activities

Net cash provided from operating activities was $307 million in 2006, $915 million in 2005 and $416 million in 2004, summarized as follows:

Operating Cash Flows	2006			2005			2004
	*(In millions)*
Net income	$	212		$	314		$	343
Net-cash charges (credits)		(2	)		441			433
Pension trust contribution*		6			(73	)		(44	)
Working capital and other		91			233			(316	)
Net cash provided from operating activities	$	307		$	915		$	416

Pension trust contributions in 2005 and 2004 are net of $34 million and $29 million of related

current year cash income tax benefits, respectively. The $6 million cash inflow in 2006 represents

income tax benefits in 2006 relating to a January 2007 pension contribution.

Net cash provided from operating activities decreased $608 million in 2006 compared to 2005 primarily due to a $10 2 million decrease in net income and a $443 million decrease in non-cash charges as described above under ?Results of Operations? and a $142 million decrease from changes in working capital and other, partially offset by a $79 million increase in after-tax pension trust contributions. The decrease in working capital and other primarily reflects the absence in 2006 of $136 million in funds received under the Energy for Education program in 2005 and changes in accounts payable of $99 million, partially offset by changes in accrued taxes of $41 million (net of taxes on pension trust contributions) and changes in accounts receivables of $19 million and accrued interest of $20 million.

Net cash provided from operating activities increased $499 million in 2005 compared to 2004 primarily due to a $549 million increase from changes in working capital and other and an $8 million increase in non-cash charges, partially offset by a $29 million decrease in net income (see ?Results of Operations?) and a $29 million decrease in after-tax pension trust contributions. The increase in working capital and other primarily reflects decreased outflows of $417 million from reduced tax payments, changes in accounts payable of $126 million and $136 million of funds received in 2005 for prepaid electric service (under a three-year Energy for Education Program with the Ohio Schools Council), partially offset by a $124 million decrease in cash provided from the settlement of receivables.

Cash Flows From Financing Activities

In 2006, 2005 and 2004, net cash used for financing activities of $935 million, $728 million and $569 million, respectively, primarily reflected the securities issues and redemptions shown below:

Securities Issued or Redeemed	2006			2005		2004
	*(In millions)*
*New Issues:*
Pollution control notes	$	-		$	146	$	30
Unsecured notes		592			-		-
	$	592		$	146	$	30
*Redemptions:*
Common Stock	$	500		$	-	$	-
FMB		1			81		63
Pollution control notes		606			271		-
Secured notes		5			56		62
Preferred stock		78			38		1
Long-term revolving credit		-			-		40
Other		1			6		6
	$	1,191		$	452	$	172

Short-term borrowings (repayments), net	$	(187	)	$	26	$	(4	)

Net cash used for financing activities increased to $935 million in 2006 from $728 million in 2005. The increase resulted from a $500 million repurchase of common stock and a net increase of $6 million in debt refinancings as shown above, partially offset by a $298 million decrease in common stock dividends to FirstEnergy. Net cash used for financing activities increased to $728 million in 2005 from $569 million in 2004. The increase resulted from a net increase of $134 million in debt refinancings as shown above and a $25 million increase in common stock dividends paid to FirstEnergy.

We had approximately $459 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $117 million of short-term indebtedness as of December 31, 2006. We have authorization from the PUCO to incur short-term debt of up to $500 million, which is available through the bank facility and the utility money pool described below. Penn has authorization from the FERC to incur short-term debt up to its charter limit of $39 million as of December 31, 2006, and also has access to the bank facility and the utility money pool.

OES Capital, our wholly owned subsidiary, has borrowings that are secured by customer accounts receivable purchased from us. OES Capital can borrow up to $170 million under a receivables financing arrangement. As a separate legal entity with separate creditors, OES Capital would have to satisfy its obligations to creditors before any of its remaining assets could be made available to us. As of December 31, 2006, the facility was undrawn.

Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to $25 million under a receivables financing arrangement which expires June 28, 2007 . As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. As of December 31, 2006, the facility was undrawn.

As of December 31, 2006, we had the aggregate capability to issue approximately $1.4 billion of additional FMB on the basis of property additions and retired bonds under the terms of our mortgage indentures. Our issuance of FMB is also subject to provisions of our senior note indenture generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, we are permitted under the indenture to incur additional secured debt not otherwise permitted by a specified exception of up to $543 million as of December 31, 2006. As a result of our redeeming all remaining outstanding preferred stock during 2006, our applicable earnings coverage test is inoperative. In the event that we would issue preferred stock in the future, the applicable earnings coverage test will govern the amount of additional preferred stock that we may issue.

As of December 31, 2006, we had approximately $400 million of capacity remaining unused under our existing shelf registration for unsecured debt securities.

On August 24, 2006, we, FirstEnergy, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a new $2.75 billion five-year revolving credit facility which replaced the prior $2 billion credit facility. Subject to specified conditions, FirstEnergy may request an increase in the total commitments available under the new facility up to a maximum of $3.25 billion. Commitments under the new facility are available until August 24, 2011, unless the lenders agree, at the request of the Borrowers, to two 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 sublimit, as well as applicable regulatory and other limitations. Our borrowing limit under the facility is $500 million and Penn?s is $50 million, subject in each case to applicable regulatory approvals.

Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower?s borrowing sublimit. Total unused borrowing capability under the credit facility and accounts receivable financing facilities was $745 million as of December 31, 2006.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of December 31, 2006, debt to total capitalization as defined under the revolving credit facility was 41% for OE and 24% for Penn.

The revolving credit facility does not contain any provisions that either restrict our ability to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in ?pricing grids?, whereby the cost of funds borrowed under the facility is related to our credit ratings.

We have the ability to borrow from our regulated affiliates and FirstEnergy to meet our short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2006 was 5.22%.

Our access to the capital markets and the costs of financing are influenced by the ratings of its securities. The ratings outlook from S&P and Fitch on all securities is stable. The ratings outlook from Moody's on all securities is positive.

Ratings of Securities	Securities	S&P	Moody?s	Fitch
FirstEnergy	Senior unsecured	BBB-	Baa3	BBB

OE	Senior unsecured	BBB-	Baa2	BBB

Penn	Senior secured	BBB+	Baa1	BBB+

On June 26, 2006, OE issued $600 million of unsecured senior notes, comprised of $250 million of 6.4% notes due 2016 and $350 million of 6.875% notes due 2036. The net proceeds from these offerings were used in July 2006 to repurchase $500 million of OE common stock from FirstEnergy, redeem approximately $61 million of our preferred stock and to reduce short-term borrowings.

In April and December of 2006, pollution control notes totaling $552 million that were formerly our obligations were refinanced and became obligations of FGCO and NGC. The proceeds from the refinancings were used to repay a portion of our associated company notes receivable from FGCO and NGC. Approximately $279 million of pollution control notes remain subject to transfer.

Cash Flows From Investing Activities

Net cash provided from investing activities was $628 million in 2006 compared to $188 million used for investing activities in 2005. The $816 million change resulted primarily from a $354 million increase in payments received on long-term notes receivable from associated companies, a $114 million increase in short-term loan repayments from associated companies, a $162 million change in cash investments and a $144 million decrease in property additions due to the generation asset transfers.

Net cash used for investing activities totaled $188 million in 2005 compared to $152 million provided from investing activities in 2004. The $340 million change resulted primarily from the absence in 2005 of $278 million of cash proceeds from certificates of deposit in 2004, loan repayments made to associated companies and $78 million of investments for an escrow fund and a mortgage indenture deposit, partially offset by a $193 million increase in payments received on long-term notes receivable from associated companies.

Our capital spending for the period 2007-2011 is expected to be about $776 million, of which approximately $146 million applies to 2007. The capital spending is primarily for property additions supporting the distribution of electricity. In addition, there are capital spending requirements related to our interests in generating plants leased from non-affiliates.

Contractual Obligations

As of December 31, 2006, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:

					2008-		2010-
Contractual Obligations	Total		2007		2009		2011		Thereafter
	*(In millions)*
Long-term debt ⁽¹⁾	$	1,294	$	4	$	181	$	66	$	1,043
Short-term borrowings		117		117		-		-		-
Interest on long-term debt		1,135		66		121		117		831
Capital leases		1		-		1		-		-
Operating leases ⁽²⁾		1,071		86		218		210		557
Pension funding ⁽³⁾		20		20		-		-		-
Purchases ⁽⁴⁾		123		3		41		18		61
Total	$	3,761	$	296	$	562	$	411	$	2,492

⁽¹⁾

Amounts reflected do not include interest on long-term debt.

⁽²⁾

Operating lease payments are net of capital trust receipts of $416.3 million (see Note 6).

⁽³⁾

We estimate that no pension contributions will be required during the 2008-2011 period to maintain our defined benefit pension plan's funding at a minimum required level as determined by government regulations. We are unable to estimate projected contributions beyond 2011. See Note 3 to the consolidated financial statemenets.

⁽⁴⁾

Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing.

Off-Balance Sheet Arrangements

We have obligations that are not included on our Consolidated Balance Sheets related to the sale and leaseback arrangements involving Perr y Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments (see Note 6). The present value of these operating lease commitments, net of trust investments, was $632 million as of December 31, 2006.

Interest Rate Risk

Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the following table which presents principal amounts and related weighted average interest rates by year of maturity for our investment portfolio, debt obligations and preferred stock with mandatory redemption provisions.

Comparison of Carrying Value to Fair Value
																There-						Fair
Year of Maturity	2007			2008			2009			2010			2011			after			Total			Value
	*(Dollars in millions)*
Assets
Investments Other Than Cash
and Cash Equivalents-
Fixed Income	$	40		$	17		$	25		$	29		$	30		$	1,411		$	1,552		$	1,618
Average interest rate		8.2	%		8.2	%		8.5	%		8.6	%		8.6	%		5.3	%		5.6	%


Liabilities Long-term Debt and Other
Long-Term Obligations:
Fixed rate	$	4		$	179		$	2		$	65		$	1		$	781		$	1,032		$	1,075
Average interest rate		8.2	%		4.1	%		8.0	%		5.5	%		9.7	%		6.5	%		6.0	%
Variable rate																$	262		$	262		$	262
Average interest rate																	3.9	%		3.9	%
Short-term Borrowings	$	117																	$	117		$	117
Average interest rate		4.0	%																	4.0	%

Equity Price Risk

Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $80 million and $67 million as of December 31, 2006 and 2005, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $8 million reduction in fair value as of December 31, 2006. As discussed in Note 5 - Fair Value of Financial Instruments, our nuclear decommissioning trust investments were transferred to NGC as part of the intra-system generation asset transfers with the exception of an amount related to our retained leasehold interests in nuclear generation assets.

Outlook

Our industry continues to transition to a more competitive environment and all of our customers can select alternative energy suppliers. We continue to deliver power to residential homes and businesses through our existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, we have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits..

Regulatory Matters

Regulatory assets are costs which have been authorized by the PUCO, the PPUC and the FERC for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred.. All regulatory assets are expected to be recovered under the provisions of our transition plan and traditional base rate proceedings.

On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO?s concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio?s findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies? termination will be withdrawn and considered to be null and void. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court?s concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29 , 2007. I n their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. No further proceedings are scheduled at this time.

	Maintaining the existing level of our base distribution rates through December 31, 2008;
	Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;
	Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of our authorized costs will occur as of December 31, 2008;
	Reducing our deferred shopping incentive balances as of January 1, 2006 by up to $75 million by accelerating the application of our accumulated cost of removal regulatory liability; and
	Recovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all of TE?s and our distribution and transmission customers through a fuel recovery mechanism. We may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the amount collected through the fuel recovery mechanism.

The following table provides our estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) for the remaining years of the RCP:


Period	Amortization
	*(In millions)*

2007	$	179
2008		208
Total Amortization	$	387

On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies? RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. On January 10, 2006, the Ohio Companies filed a Motion for Clarification seeking clarity on a number of issues. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies? previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies? requests to:

	Recognize fuel and distribution deferrals commencing January 1, 2006;
	Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff;
	Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and
	Clarify that distribution expenditures do not have to be ?accelerated? in order to be deferred.

The PUCO approved the Ohio Companies? methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies? Motion. On February 3, 2006, several other parties filed applications for rehearing, which the PUCO denied on March 1, 2006. Two of these parties subsequently filed notices of appeal with the Supreme Court of Ohio. The Ohio Supreme Court scheduled this case for oral argument on February 27, 2007. On January 31, 2007, the Ohio Companies filed a stipulation which, among other matters and subject to PUCO approval, affirmed that the supplemental stipulation in the RCP would be implemented. This stipulation was approved by the PUCO on February 14, 2007.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. On January 20, 2006, the OCC sought rehearing of the PUCO?s approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of the Ohio Companies' case with a similar case involving Dayton Power & Light Company. Oral arguments were heard on May 10, 2006. On November 29, 2006, the Ohio Supreme Court issued its opinion upholding the PUCO?s determination that the Ohio Companies may defer transmission and ancillary service related costs incurred on and after December 30, 2004. The Ohio Supreme Court also determined that the PUCO erred when it denied the OCC intervention, but further ruled that such error did not prejudice OCC and, therefore, the Ohio Supreme Court did not reverse or remand the PUCO on this ground. The Ohio Supreme Court also determined that the OCC?s appeal was not premature. No party filed a motion for reconsideration with the Ohio Supreme Court.

The terms of the settlement provide for modification of both the Ohio and Penn power supply agreements with FES. Under the Ohio power supply agreement, separate rates are established for the Ohio Companies? PLR requirements; special retail contract requirements, wholesale contract requirements, and interruptible buy-through retail load requirements. For their PLR and special retail contract requirements, the Ohio Companies will pay FES no more than the lower of (i) the sum of the retail generation charge, the rate stabilization charge, the fuel recovery mechanism charge, and FES? actual incremental fuel costs for such sales; or (ii) the wholesale price cap. Different wholesale price caps are imposed for PLR sales, special retail contracts, and wholesale contracts. The wholesale price for interruptible buy-through retail load requirements is limited to the actual spot price of power obtained by FES to provide this power. FES billed the Ohio Companies for the additional amount payable to FES for incremental fuel costs on power supplied during 2006. The total power supply cost billed by FES was lower in each case than the wholesale price caps specified in the settlement accepted by the FERC. In addition, pursuant to the settlement, the wholesale rate charged by FES under the Penn power supply agreement can be no greater than the generation component of charges for retail PLR load in Pennsylvania. The modifications to the Ohio and Pennsylvania power supply agreements became effective January 1, 2006. The Penn supply agreement subject to the settlement expired at midnight on December 31, 2006.

As a result of Penn?s PLR competitive solicitation process approved by the PPUC for the period January 1, 2007 through May 31, 2008, FES was selected as the winning bidder for a number of the tranches for individual customer classes. The balance of the tranches will be supplied by unaffiliated power suppliers. On October 2, 2006, FES filed an application with the FERC under Section 205 of the Federal Power Act for authorization to make these affiliate sales to Penn. Interventions or protests were due on this filing on October 23, 2006. Penn was the only party to file an intervention in this proceeding. This filing was accepted by the FERC on November 15, 2006, and no requests for rehearing were filed.

On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market. MISO contends that the filing will integrate operating reserves into MISO?s existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch. The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO. MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region. MISO is targeting implementation for the second or third quarter of 2008. The FERC has established March 23, 2007, as the date for interested parties to submit comments addressing the filing. The filing has not yet been fully evaluated to assess its impact on our operations.

See Note 9 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio and Pennsylvania and a detailed discussion of reliability initiatives, including initiatives by the PPUC, that impact Penn.

Environmental Matters

We accrue environmental liabilities only when we conclude that it is probable that we have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in our determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

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 New Source Review litigation. This settlement agreement, which is in the form of a consent decree, was approved by the Court on July 11, 2005, and requires reductions of NO _X and SO ₂ emissions at the W. H. Sammis Plant and other 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 we fail to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, we could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation are currently estimated to be $1.5 billion ($400 million of which is expected to be spent in 2007, with the largest portion of the remaining $1.1 billion expected to be spent in 2008 and 2009).

Other Legal Proceedings

Power Outage and Related Litigation-

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy?s service area. The U.S. - Canada Power System Outage Task Force?s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy?s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy?s Web site (www.doe.gov). We believe 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. We remain 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 proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

FirstEnergy companies also are defending five separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants?three in one case and four in the other?sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Three other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these three cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc., as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. On March 7, 2006, the PUCO issued a ruling, consolidating all of the pending outage cases for hearing; limiting the litigation to service-related claims by customers of the Ohio operating companies; dismissing FirstEnergy as a defendant; and ruling that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on October 16, 2007.

On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid to numerous insureds who allegedly suffered losses as a result of the August 14, 2003 outages. All of the insureds appear to be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006. On January 18, 2007, the Court granted the Companies? motion to dismiss the case. It is unknown whether or not the matter will be further appealed. No estimate of potential liability is available for any of these cases.

We are vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on our financial condition, results of operations and cash flows.

Other Legal Matters-

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to our normal business operations pending against us. The other potentially material items not otherwise discussed above are described below.

On October 20, 2004, we were notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the now repealed PUHCA. Concurrent with this notification, we received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, we received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005, additional information was requested regarding Davis-Besse-related disclosures, which has been provided. We have cooperated fully with the informal inquiry and continue to do so with the formal investigation.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on our financial condition, results of operations and cash flows.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

Critical Accounting Policies

We prepare our consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Our more significant accounting policies are described below.

Regulatory Accounting

We are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on the costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. We regularly review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.

Revenue Recognition

We follow the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, weather-related impacts, prices in effect for each customer class and electricity provided by alternative suppliers.

Pension and Other Postretirement Benefits Accounting

Our reported costs of providing non-contributory qualified and non-qualified defined pension benefits and post employment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.

Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make 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 are also affected by changes to 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 for pension and OPEB costs.

In accordance with SFAS 87, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience.

As of December 31, 2006, we adopted SFAS 158 which requires a net liability or asset to be recognized for the overfunded or underfunded status of our defined benefit pension and other postretirement benefit plans on the balance sheet and recognize changes in funded status in the year in which the changes occur through other comprehensive income. We will continue to apply the provisions of SFAS 87 and SFAS 106 in measuring plan assets and benefit obligations as of the balance sheet date and in determining the amount of net periodic benefit cost. FirstEnergy?s underfunded status as of December 31, 2006 is $637 million.

In selecting an assumed discount rate, we consider 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 discount rate as of December 31, 2006 is 6.00% from 5.75% and 6.00% used as of December 31, 2005 and 2004, respectively.

FirstEnergy?s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. In 2006, 2005 and 2004, the FirstEnergy plan assets actually earned $567 million or 12.5%, $325 million or 8.2% and $415 million or 11.1% , respectively. FirstEnergy?s pension costs in 2006, 2005 and 2004 were computed using an assumed 9.0% rate of return on plan assets which generated $396 million, $345 million and $286 million expected returns on plan assets, respectively. The 2006 expected return was based upon projections of future returns and FirstEnergy?s pension trust investment allocation of approximately 64% equities, 29% bonds, 5% real estate, 1% private equities and 1% cash. The gains or losses generated as a result of the difference between expected and actual returns on plan assets are deferred and amortized and will increase or decrease future net periodic pension expense, respectively.

FirstEnergy?s pension and OPEB expense was $94 million in 2006 and $131 million in 2005. On January 2, 2007 FirstEnergy made a $300 million voluntary contribution to its pension plan (our share was $20 million). In addition during 2006, FirstEnergy amended its OPEB plan effective in 2008 to cap its monthly contribution for many of the retirees and their spouses receiving subsidized health care coverage.. As a result of the $300 million voluntary contribution and the amendment to the OPEB plan effective in 2008, we expect the pension and OPEB costs for 2007 to be a credit of $94 million for FirstEnergy.

Health care cost trends have significantly increased and will affect future OPEB costs. The 2006 and 2005 composite health care trend rate assumptions are approximately 9-11%, gradually decreasing to 5% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. The effect on OE's portion of pension and OPEB costs from changes in key assumptions are as follows:

Increase in Costs from Adverse Changes in Key Assumptions

Assumption	Adverse Change			Pension		OPEB		Total
				*(In millions)*
Discount rate		Decrease by 0.25	%	$	1.9	$	0.2	$	2.1
Long-term return on assets		Decrease by 0.25	%	$	2.2	$	-	$	2.2
Health care trend rate		Increase by 1	%		na	$	0.7	$	0.7

Ohio Transition Cost Amortization

In connection with our Ohio transition plan, the PUCO determined allowable transition costs based on amounts recorded on our regulatory books. These costs exceeded those deferred or capitalized on our balance sheet prepared under GAAP since they included certain costs which had not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). We use an effective interest method for amortizing transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in our RSP. In computing the transition cost amortization, we include only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off-balance sheet costs and the return associated with these costs are recognized as income when received. Amortization of deferred customer shopping incentives and interest costs are equal to the related revenue recovery that is recognized under the RCP (see Note 2 (A)).

Long-Lived Assets

In accordance with SFAS 144, we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, we recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows).

The calculation of future cash flows is based on assumptions, estimates and judgment about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment.

Asset Retirement Obligations

In accordance with SFAS 143 and FIN 47, we recognize an ARO for the future decommissioning of our nuclear power plants and future remediation of other environmental liabilities associated with all of our long-lived assets. The ARO liability represents an estimate of the fair value of our current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. We use an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license, settlement based on an extended license term and expected remediation dates.

New Accounting Standards and Interpretations

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

In February 2007, FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value. The Standard requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the 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, Fair Value Measurements, and SFAS 107, Disclosures about Fair Value of Financial Instruments. We are currently evaluating the impact of this Statement on our financial statements.

SFAS 157 - ?Fair Value Measurements?

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 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. We are currently evaluating the impact of this Statement on its financial statements.

FIN 48 - ?Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109?

In June 2006, the FASB issued FIN 48 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise?s financial statements in accordance with FASB Statement No. 109, ?Accounting for Income Taxes.? This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation will be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit to recognize in the financial statements. This interpretation is effective for fiscal years beginning after December 15, 2006. We do not expect this Statement to have a material impact on our financial statements.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME



For the Years Ended December 31,	2006			2005			2004
	*(In thousands)*
REVENUES (Note 2(I)):
Electric sales	$ 2,312,956			$ 2,861,043			$ 2,834,538
Excise tax collections	114,500			114,510			111,045
		2,427,456			2,975,553			2,945,583

EXPENSES (Note 2(I)):
Fuel		11,047			53,113			56,560
Purchased power		1,275,975			939,193			970,670
Nuclear operating costs		186,377			337,901			375,309
Other operating costs		378,717			404,763			336,772
Provision for depreciation		72,982			108,583			122,413
Amortization of regulatory assets		190,245			457,205			411,326
Deferral of new regulatory assets		(159,465	)		(151,032	)		(100,633	)
General taxes		180,446			193,284			180,523
Total expenses		2,136,324			2,343,010			2,352,940

OPERATING INCOME		291,132			632,543			592,643

OTHER INCOME (EXPENSE) (Note 2(I)):
Investment income		130,853			99,269			96,030
Miscellaneous expense		1,751			(25,190	)		(765	)
Interest expense		(90,355	)		(75,388	)		(71,491	)
Capitalized interest		2,198			10,849			7,211
Subsidiary's preferred stock dividend requirements		(597	)		(1,689	)		(2,560	)
Total other income		43,850			7,851			28,425

INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		334,982			640,394			621,068

INCOME TAXES		123,343			309,996			278,302

INCOME BEFORE CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE		211,639			330,398			342,766

Cumulative effect of a change in accounting principle
(net of income tax benefit of $9,223,000) (Note 2(G))		-			(16,343	)		-

NET INCOME		211,639			314,055			342,766

PREFERRED STOCK DIVIDEND REQUIREMENTS
AND REDEMPTION PREMIUM		4,552			2,635			2,502

EARNINGS ON COMMON STOCK	$	207,087		$	311,420		$	340,264


The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS


As of December 31,	2006		2005
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	712		$	929
Receivables-
Customers (less accumulated provisions of $15,033,000 and $7,619,000, respectively,
for uncollectible accounts)		234,781			290,887
Associated companies		141,084			187,072
Other (less accumulated provisions of $1,985,000 and $4,000, respectively,
for uncollectible accounts)		13,496			15,327
Notes receivable from associated companies		458,647			536,629
Prepayments and other		13,606			93,129
		862,326			1,123,973
UTILITY PLANT:
In service		2,632,207			2,526,851
Less - Accumulated provision for depreciation		1,021,918			984,463
		1,610,289			1,542,388
Construction work in progress		42,016			58,785
		1,652,305			1,601,173
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		1,219,325			1,758,776
Investment in lease obligation bonds (Note 6)		291,393			325,729
Nuclear plant decommissioning trusts		118,209			103,854
Other		38,160			44,210
		1,667,087			2,232,569
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		741,564			774,983
Prepaid pension costs		68,420			224,813
Property taxes		60,080			52,875
Unamortized sale and leaseback costs		50,136			55,139
Other		18,696			31,752
		938,896			1,139,562
	$	5,120,614		$	6,097,277
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	159,852		$	280,255
Short-term borrowings-
Associated companies		113,987			57,715
Other		3,097			143,585
Accounts payable-
Associated companies		115,252			172,511
Other		13,068			9,607
Accrued taxes		187,306			163,870
Accrued interest		24,712			8,333
Other		64,519			61,726
		681,793			897,602
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		1,972,385			2,502,191
Preferred stock not subject to mandatory redemption		-			60,965
Preferred stock of consolidated subsidiary not subject to mandatory redemption		-			14,105
Long-term debt and other long-term obligations		1,118,576			1,019,642
		3,090,961			3,596,903
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		674,288			769,031
Accumulated deferred investment tax credits		20,532			24,081
Asset retirement obligations		88,223			82,527
Retirement benefits		167,510			291,051
Deferred revenues - electric service programs		86,710			121,693
Other		310,597			314,389
		1,347,860			1,602,772
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	5,120,614		$	6,097,277


The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

	Shares Outstanding				Dollars in Thousands
As of December 31,	2006		2005		2006		2005

COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, 175,000,000 shares authorized		80		100	$	1,708,441	$	2,297,253
Accumulated other comprehensive income (loss) (Note 2(F))						3,208		4,094
Retained earnings (Note 10(A))						260,736		200,844
Total						1,972,385		2,502,191


PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION (Note 10(B)):
Cumulative, $100 par value, 6,000,000 shares authorized-
3.90 %		-		152,510		-		15,251
4.40 %		-		176,280		-		17,628
4.44 %		-		136,560		-		13,656
4.56 %		-		144,300		-		14,430
Total		-		609,650		-		60,965


PREFERRED STOCK OF CONSOLIDATED SUBSIDIARY NOT SUBJECT TO
MANDATORY REDEMPTION (Note 10(B)):
Pennsylvania Power Company-
Cumulative, $100 par value, 1,200,000 shares authorized-
4.24 %		-		40,000		-		4,000
4.25 %		-		41,049		-		4,105
4.64 %		-		60,000		-		6,000
Total		-		141,049		-		14,105


LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 10(C)):
Ohio Edison Company-
Secured notes:
* 3.050% due 2015						-		19,000
* 3.250% due 2015						-		50,000
* 3.200% due 2016						-		47,725
7.050% due 2020						-		60,000
5.375% due 2028						13,522		13,522
* 3.780% due 2029						100,000		100,000
* 3.750% due 2029						6,450		6,450
* 3.050% due 2030						-		60,400
* 3.350% due 2031						-		69,500
* 3.100% due 2033						-		12,300
5.450% due 2033						-		14,800
* 3.350% due 2033						-		50,000
* 3.100% due 2033						-		108,000
Limited Partnerships-
7.24% weighted average interest rate due 2006-2010						8,253		12,859
Total						128,225		624,556

* Denotes variable rate issue with applicable year-end interest rate shown.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)

	Dollars in Thousands
As of December 31,	2006			2005

LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Cont'd)
Ohio Edison Company-
Unsecured notes:
4..000% due 2008	$	175,000		$	175,000
* 3.900% due 2014		50,000			50,000
5..450% due 2015		150,000			150,000
6..400% due 2016		250,000			-
* 4.020% due 2018		33,000			33,000
* 3.960% due 2018		23,000			23,000
* 3.950% due 2023		50,000			50,000
6..875% due 2036		350,000			-
Total		1,081,000			481,000


Pennsylvania Power Company-
First mortgage bonds:
9..740% due 2007-2019		12,695			13,669
7..625% due 2023		6,500			6,500
Total		19,195			20,169

Secured notes:
5..400% due 2013		1,000			1,000
5..400% due 2017		-			10,600
* 3.300% due 2017		-			17,925
5.900% due 2018		-			16,800
* 3.300% due 2021		-			10,525
6..150% due 2023		-			12,700
* 3.610% due 2027		-			10,300
5..375% due 2028		1,734			1,734
5..450% due 2028		-			6,950
6..000% due 2028		-			14,250
Total		2,734			102,784

Unsecured notes:
* 3.500% due 2029		-			14,500
5..390% due 2010 to associated company		62,900			62,900
Total		62,900			77,400


Capital lease obligations (Note 6)		362			3,312
Net unamortized discount on debt		(15,988	)		(9,324	)
Long-term debt due within one year		(159,852	)		(280,255	)
Total long-term debt and other long-term obligations		1,118,576			1,019,642
TOTAL CAPITALIZATION	$	3,090,961		$	3,596,903


* Denotes variable rate issue with applicable year-end interest rate shown.

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

										Accumulated
										Other
	Comprehensive			Number			Carrying			Comprehensive			Retained
	Income			of Shares			Value			Income (Loss)			Earnings
	*(Dollars in thousands)*
Balance, January 1, 2004					100		$	2,098,729		$	(38,693	)	$	522,934
Net income	$	342,766												342,766
Minimum liability for unfunded retirement
benefits, net of $5,516,000 of income tax benefits		(7,552	)								(7,552	)
Unrealized loss on investments, net of
$533,000 of income tax benefits		(873	)								(873	)
Comprehensive income	$	334,341
Cash dividends on preferred stock														(2,502	)
Cash dividends on common stock														(421,000	)
Balance, December 31, 2004					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											(8,840	)
Affiliated company asset transfers (Note 14)								(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

CONSOLIDATED STATEMENTS OF PREFERRED STOCK

	Not Subject to						Subject to
	Mandatory Redemption						Mandatory Redemption*
	Number			Par			Number			Par
	of Shares			Value			of Shares			Value
	*(Dollars in thousands)*

Balance, January 1, 2004		1,000,699		$	100,070			135,000		$	13,500
Redemptions-
7.625% Series								(7,500	)		(750	)
Balance, December 31, 2004		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		-		$	-			-		$	-

* Preferred stock subject to mandatory redemption is classified as debt under SFAS 150.

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS


For the Years Ended December 31,		2006			2005			2004
	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	211,639		$	314,055		$	342,766
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation			72,982			108,583			122,413
Amortization of regulatory assets			190,245			457,205			411,326
Deferral of new regulatory assets			(159,465	)		(151,032	)		(100,633	)
Nuclear fuel and lease amortization			735			45,769			42,811
Amortization of lease costs			(7,928	)		(6,365	)		(5,170	)
Deferred income taxes and investment tax credits, net			(68,259	)		(29,750	)		(44,469	)
Accrued compensation and retirement benefits			5,004			14,506			35,840
Cumulative effect of a change in accounting principle			-			16,343			-
Pension trust contribution			-			(106,760	)		(72,763	)
Decrease (increase) in operating assets-
Receivables			103,925			84,688			209,130
Materials and supplies			-			(3,367	)		(10,259	)
Prepayments and other current assets			1,275			(1,778	)		1,286
Increase (decrease) in operating liabilities-
Accounts payable			(53,798	)		45,149			(80,738	)
Accrued taxes			23,436			10,470			(406,945	)
Accrued interest			16,379			(3,659	)		(6,722	)
Electric service prepayment programs			(34,983	)		121,692			-
Other			5,882			(464	)		(21,519	)
Net cash provided from operating activities			307,069			915,285			416,354

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt			592,180			146,450			30,000
Short-term borrowings, net			-			26,404			-
Redemptions and Repayments-
Common stock			(500,000	)		-			-
Preferred stock			(78,480	)		(37,750	)		(750	)
Long-term debt			(613,002	)		(414,020	)		(170,997	)
Short-term borrowings, net			(186,511	)		-			(4,015	)
Dividend Payments-
Common stock			(148,000	)		(446,000	)		(421,000	)
Preferred stock			(1,423	)		(2,635	)		(2,502	)
Net cash used for financing activities			(935,236	)		(727,551	)		(569,264	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(123,210	)		(266,823	)		(235,022	)
Proceeds from nuclear decommissioning trust fund sales			42,021			428,954			173,976
Investments in nuclear decommissioning trust funds			(44,095	)		(460,494	)		(205,516	)
Loan repayments from (loans to) associated companies, net			78,101			(35,553	)		120,706
Collection of principal on long-term notes receivable			553,734			199,848			7,348
Cash investments			112,584			(49,270	)		28,877
Proceeds from certificates of deposit			-			-			277,763
Other			8,815			(4,697	)		(15,875	)
Net cash provided from (used for) investing activities			627,950			(188,035	)		152,257

Net decrease in cash and cash equivalents			(217	)		(301	)		(653	)
Cash and cash equivalents at beginning of year			929			1,230			1,883
Cash and cash equivalents at end of year		$	712		$	929		$	1,230

SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)		$	57,243		$	67,239		$	65,765
Income taxes		$	156,610		$	285,819		$	419,123

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF TAXES


For the Years Ended December 31,	2006			2005			2004
	*(In thousands)*
GENERAL TAXES:
Ohio kilowatt-hour excise*	$	95,154		$	94,085		$	91,811
State gross receipts*		19,346			20,425			19,234
Real and personal property		54,908			67,438			58,000
Social security and unemployment		7,419			7,481			7,048
Other		3,619			3,855			4,430
Total general taxes	$	180,446		$	193,284		$	180,523

PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	161,880		$	274,676		$	246,864
State		29,722			74,293			75,907
		191,602			348,969			322,771
Deferred, net-
Federal		(57,330	)		(60,252	)		(23,668	)
State		(7,241	)		36,798			(5,512	)
		(64,571	)		(23,454	)		(29,180	)
Investment tax credit amortization		(3,688	)		(15,519	)		(15,289	)
Total provision for income taxes	$	123,343		$	309,996		$	278,302


RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	334,982		$	640,394		$	621,068
Federal income tax expense at statutory rate	$	117,244		$	224,138		$	217,374
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits		(3,688	)		(15,519	)		(15,289	)
State income taxes, net of federal income tax benefit		14,613			72,209			45,757
Amortization of tax regulatory assets		3,744			7,341			6,130
Penalties		-			2,975			-
Competitive transition charge		2,685			31,934			27,889
Low income housing and franchise credits		(7,001	)		(6,796	)		(8,615	)
Other, net		(4,254	)		(6,286	)		5,056
Total provision for income taxes	$	123,343		$	309,996		$	278,302

ACCUMULATED DEFERRED INCOME TAXES AS OF
DECEMBER 31:
Property basis differences	$	496,670		$	480,859		$	451,269
Allowance for equity funds used during construction		22,738			25,470			27,730
Regulatory transition charge		(28,341	)		6,653			154,015
Asset retirement obligations		9,928			-			21,253
Customer receivables for future income taxes		31,283			33,946			39,266
Deferred sale and leaseback costs		(54,515	)		(59,225	)		(63,432	)
Unamortized investment tax credits		(8,291	)		(9,605	)		(23,510	)
Deferred gain on asset sales to affiliated companies		46,809			50,304			51,716
Other comprehensive income		(15,143	)		2,689			(33,268	)
Retirement benefits		30,334			30,849			(6,202	)
Deferred customer shopping incentive		68,457			123,029			94,002
Other		74,359			84,062			53,437

Net deferred income tax liability	$	674,288		$	769,031		$	766,276


* Collected from customers through regulated rates and included in revenue in the Consolidated Statements of Income.

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION:

The consolidated financial statements include OE (Company) and its wholly owned subsidiaries.. Penn is the Company's principal operating subsidiary. The Company is a wholly owned subsidiary of FirstEnergy. FirstEnergy also holds directly all of the issued and outstanding common shares of its other principal electric utility operating subsidiaries, including CEI, TE, ATSI, JCP&L, Met-Ed and Penelec. In the fourth quarter of 2005, the Companies completed the intra-system transfers of their non-nuclear and nuclear generation assets to FGCO and NGC, respectively. See Note 14 - FirstEnergy Intra-System Generation Asset Transfers for further discussion.

The Companies follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, PUCO, the PPUC and the FERC. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.

The Company consolidates all majority-owned subsidiaries over which the Company exercises control and, when applicable, entities for which the Company has a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. Investments in non -consolidated affiliates (20-50% owned companies, joint ventures and partnerships) over which the Company has the ability to exercise significant influence, but not control, are accounted for on the equity basis.

Certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications did not change previously reported earnings for 2005 and 2004.

Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

(A)

ACCOUNTING FOR THE EFFECTS OF REGULATION-

The Companies account for the effects of regulation through the application of SFAS 71 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 regulatory assets are removed from the balance sheet in accordance with the guidance in SFAS 101.

Regulatory Assets-

The Companies recognize, as regulatory assets, costs which the FERC, PUCO and PPUC 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 Companies' respective transition and rate restructuring plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies c ontinue the application of SFAS 71 to those operations.

Net regulatory assets on the Consolidated Balance Sheets are comprised of the following:

	2006*			2005*
	*(In millions)*
Regulatory transition costs	$	280		$	369
Customer shopping incentives		174			325
Customer receivables for future income taxes		81			88
Loss on reacquired debt		24			22
Asset removal costs		(3	)		(80	)
MISO transmission costs		44			49
Fuel costs?RCP		57			-
Distribution costs?RCP		74			-
Other		10			2
Total	$	741		$	775

Penn had net regulatory liabilities of approximately $69 million and $59 million included in Other Noncurrent

Liabilities on the Consolidated Balance Sheets as of December 31, 2006 and 2005, respectively.

The Company had been deferring customer shopping incentives and interest costs (Extended RTC) as new regulatory assets in accordance with its prior transition and rate stabilization plans. As a result of the RCP approved in January 2006, the Extended RTC balance ($325 million as of December 31, 2005) was reduced on January 1, 2006 by $75 million by accelerating the application of the Company's accumulated cost of removal regulatory liability against the Extended RTC balance. In accordance with the RCP, the recovery periods for the aggregate of the regulatory transition costs and the Extended RTC amounts were adjusted so that recovery of these aggregate amounts through the Company's RTC rate component began on January 1, 2006, with full recovery expected to be completed as of December 31, 2008. At the end of the recovery period, any remaining unamortized regulatory transition costs and Extended RTC balances will be eliminated, first, by applying any remaining cost of removal regulatory liability balance; any remaining regulatory transition costs and Extended RTC balances would 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 RCP allows the Ohio Companies to defer certain increased fuel costs above the amount collected through a PUCO approved fuel recovery mechanism. See Note 9 for further discussion of the recovery of the shopping incentives and the new cost deferrals.

Transition Cost Amortization-

The Company amortizes transition costs (see Note 9) 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) for the remaining years of the RCP:

Amortization
Period	Amortization
	*(In millions)*
2007	$	179
2008		208
Total Amortization	$	387

(B) CASH AND SHORT-TERM FINANCIAL INSTRUMENTS-

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.

(C) REVENUES AND RECEIVABLES-

The Companies' principal business is providing electric service to customers in Ohio and Pennsylvania. The Companies' retail customers are 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, 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, 2006, with respect to any particular segment of the Companies' customers. Total customer receivables were $235 million (billed - $127 million and unbilled - $108 million) and $291 million (billed - $177 million and unbilled - $114 million) as of December 31, 2006 and 2005, respectively.

The Company sells substantially all of its retail customer receivables to OES Capital, a wholly owned subsidiary of OE. The receivables financing agreement expires on December 5, 2007.

(D) UTILITY PLANT AND DEPRECIATION-

Utility plant reflects original cost of construction (except for the Company?s nuclear leasehold interests which were adjusted to fair value) 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.. The Companies' accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.

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 annual composite rate for the Company's electric plant was approximately 2.8% in 2006, 2.1% in 2005 and 2.3% in 2004. The annual composite rate for Penn's electric plant was approximately 2.6% in 2006, 2.4% in 2005 and 2.2% in 2004.

Asset Retirement Obligations

The Companies recognize a liability 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, "Asset Retirement Obligations."

(E) ASSET IMPAIRMENTS-

Long-Lived Assets-

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.

Investments-

At the end of each reporting period, the Company evaluates its 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. The Company first considers its intent and ability to hold the investment until recovery and then considers, 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, the Company began recognizing in earnings the unrealized losses on available-for-sale securities held in the nuclear decommissioning trusts as the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of the other-than-temporary impairment. The fair value and unrealized gains and losses of the Company's investments are disclosed in Note 5(B) and (C).

(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 excluding the effect from the adoption of SFAS 158 as of December 31, 2006, except those resulting from transactions with FirstEnergy and preferred stockholders. As of December 31, 2006, AOCL consisted of a net liability for unfunded retirement benefits due to the implementation of SFAS 158, net of tax benefits (see Note 3) of $9 million and unrealized gains on investments in securities available for sale of $12 million. As of December 31, 2005, AOCI consisted of unrealized gains on investments in securities available for sale of $4 million.

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

Results in 2005 include an after-tax charge of $16 million recorded upon the adoption of FIN 47 in December 2005. The Company identified applicable legal obligations as defined under the new standard at its retired generating units, substation control rooms, service center buildings, line shops and office buildings, identifying asbestos as the primary conditional ARO. The Company recorded a conditional ARO liability of $27 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption, an asset retirement cost of $9 million recorded as part of the carrying amount of the related long-lived asset, and offsetting accumulated depreciation of $9 million. The Company charged regulatory liabilities for $1 million upon adoption of FIN 47 for the transition amounts related to establishing the ARO for asbestos removal from substation control rooms and service center buildings. The remaining cumulative effect adjustment for unrecognized depreciation and accretion of $26 million was charged to income ($16 million, net of tax). The adoption of FIN 47 had an immaterial impact on Penn?s year ended December 31, 2005 results (see Note 11).

(H) INCOME TAXES-

Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. The Company records 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 the amounts used 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 assets and liabilities related to tax and accounting basis differences and tax credit carryforwards are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. The Companies are included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Companies recognizing any tax losses or credits they contribute to the consolidated return (see Note 8 for Ohio Tax Legislation discussion).

(I) TRANSACTIONS WITH AFFILIATED COMPANIES-

Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily ATSI, FES, NGC and FESC. The Ohio transition plan resulted in the corporate separation of FirstEnergy's regulated and unregulated operations in 2001. In the fourth quarter of 2005, the Companies, CEI and TE completed the intra-system transfers of their generation assets to FGCO and NGC (see Note 14). This resulted in the elimination of the fossil generating units lease arrangement and the nuclear generation PSA revenues with the exception of those revenues related to the leasehold interests (see Note 6) which were not included in the transfer. The Companies are now receiving interest income from FGCO and NGC on the associated companies notes received in exchange for the transferred net assets. The Companies continue to purchase their power from FES to meet their PLR obligations (see Note 9 for further discussion). The primary affiliated companies transactions are as follows:

	2006		2005		2004
	*(In millions)*
Revenues:
PSA revenues from FES	$	80	$	355	$	416
Generating units rent from FES		-		146		178
Ground lease with ATSI		12		12		12

Expenses:
Purchased power under PSA		1,264		938		970
FESC support services		94		90		91

Other Income:
Interest income from ATSI		15		16		16
Interest income from FGCO and NGC		59		9		9
Interest income from FirstEnergy		25		22		-

FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Companies from FESC, a subsidiary 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. 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.

3. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy?s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy made a $300 million voluntary cash contribution to its qualified pension plan on January 2, 2007 (Companies? share was $20 million). Projections indicated that additional cash contributions will not be required before 2016.

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. 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.

In December 2006, FirstEnergy adopted SFAS 158. This Statement requires an employer 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. OE?s incremental impact of adopting SFAS 158 was a decrease of $231 million in pension assets, a decrease of $200 million in pension liabilities and a decrease in AOCL of $9 million, net of tax.

With the exception of the Companies? share of the net pension (asset) liability at the end of year and net periodic pension expense, the following tables detail the Consolidated FirstEnergy pension plan and OPEB.

Obligations and Funded Status	Pension Benefits						Other Benefits
As of December 31	2006			2005			2006			2005
	*(In millions)*
Change in benefit obligation
Benefit obligation as of January 1	$	4,750		$	4,364		$	1,884		$	1,930
Service cost		83			77			34			40
Interest cost		266			254			105			111
Plan participants? contributions		-			-			20			18
Plan amendments		3			15			(620	)		(312	)
Medicare retiree drug subsidy		-			-			6			-
Actuarial (gain) loss		33			310			(119	)		197
Benefits paid		(274	)		(270	)		(109	)		(100	)
Benefit obligation as of December 31	$	4,861		$	4,750		$	1,201		$	1,884

Change in fair value of plan assets
Fair value of plan assets as of January 1	$	4,524		$	3,969		$	573		$	564
Actual return on plan assets		567			325			69			33
Company contribution		-			500			54			58
Plan participants? contribution		-			-			20			18
Benefits paid		(273	)		(270	)		(109	)		(100	)
Fair value of plan assets as of December 31	$	4,818		$	4,524		$	607		$	573

Funded status	$	(43	)	$	(226	)	$	(594	)	$	(1,311	)

Accumulated benefit obligation	$	4,447		$	4,327

Amounts Recognized in the Statement of
Financial Position
Noncurrent assets	$	-		$	1,023		$	-		$	-
Current liabilities		-			-			-			-
Noncurrent liabilities		(43	)		-			(594	)		(1,057	)
Net pension asset (liability) as of December 31	$	(43	)	$	1,023		$	(594	)	$	(1,057	)
Companies? share of net pension asset (liability) at end of year	$	68		$	225		$	(167	)	$	(291	)

Amounts Recognized in
Accumulated Other Comprehensive Income
Prior service cost (credit)	$	63		$	-		$	(1,190	)	$	-
Actuarial loss		982			-			702			-
Net amount recognized	$	1,045		$	-		$	(488	)	$	-

Assumptions Used to Determine
Benefit Obligations As of December 31
Discount rate		6.00	%		5.75	%		6.00	%		5.75	%
Rate of compensation increase		3.50	%		3.50	%

Allocation of Plan Assets
As of December 31
Asset Category
Equity securities		64	%		63	%		72	%		71	%
Debt securities		29			33			26			27
Real estate		5			2			1			-
Private equities		1			-			-			-
Cash		1			2			1			2
Total		100	%		100	%		100	%		100	%

Estimated Items to be Amortized in 2007 Net
Periodic Pension Cost from Accumulated	Pension		Other
Other Comprehensive Income	Benefits		Benefits
	*(In millions)*
Prior service cost (credit)	$	10	$	(149	)
Actuarial loss	$	41	$	45

	Pension Benefits									Other Benefits
Components of Net Periodic Benefit Costs	2006			2005			2004			2006			2005			2004
	*(In millions)*
Service cost	$	83		$	77		$	77		$	34		$	40		$	36
Interest cost		266			254			252			105			111			112
Expected return on plan assets		(396	)		(345	)		(286	)		(46	)		(45	)		(44	)
Amortization of prior service cost		10			8			9			(76	)		(45	)		(40	)
Recognized net actuarial loss		58			36			39			56			40			39
Net periodic cost	$	21		$	30		$	91		$	73		$	101		$	103
Companies? share of net periodic cost (credit)	$	(6	)	$	-		$	7		$	17		$	28		$	28

Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost	Pension Benefits									Other Benefits
for Years Ended December 31		2006			2005			2004			2006			2005			2004
Discount rate		5.75	%		6.00	%		6.25	%		5.75	%		6.00	%		6.25	%
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	%

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 the Companies? pension trusts. The long-term rate of return is developed considering the portfolio?s asset allocation strategy.

Assumed Health Care Cost Trend Rates
As of December 31	2006			2005
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)		2011-2013			2010-2012

	1-Percentage-		1-Percentage-
	Point Increase		Point Decrease
	*(In millions)*
Effect on total of service and interest cost	$	6	$	(5	)
Effect on accumulated postretirement benefit obligation	$	33	$	(29	)

Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets:

	Pension		Other
	Benefits		Benefits
	*(In millions)*
2007	$	247	$	91
2008		249		91
2009		256		94
2010		269		98
2011		280		101
Years 2012- 2016		1,606		537

4. ESOP:

FirstEnergy?s ESOP Trust funds most of the matching contribution for FirstEnergy's 401(k) savings plan. All of the Companies? full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. The ESOP borrowed $200 million from the Company and acquired 10,654,114 shares of the Company's common stock (subsequently converted to FirstEnergy common stock) through market purchases. Dividends on ESOP shares are used to service the debt. Shares are released from the ESOP on a pro rata basis as debt service payments are made. In 2005, the ESOP loan was refinanced ($66 million principal amount) and its term was extended by three years.

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 financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations as disclosed in the Consolidated Statements of Capitalization as of December 31:

	2006				2005
	Carrying		Fair		Carrying		Fair
		Value		Value		Value		Value
	*(In millions)*
Long-term debt	$	1,294	$	1,337	$	1,306	$	1,308

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 a corporation with credit ratings similar to the Companies' ratings.

(B) INVESTMENTS-

Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities. The Company periodically evaluates its 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 security?s fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. The following table provides the approximate fair value and related carrying amounts of investments excluding nuclear decommissioning trust funds and investments of $35 million and $41 million for 2006 and 2005, respectively, excluded by SFAS 107, ?Disclosures about Fair Values of Financial Instruments?, as of December 31:

	2006				2005
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	*(In millions)*
Notes receivable	$	1,219	$	1,251	$	1,758	$	1,798
Lease obligation bonds		291		325		326		368
Equity securities		3		3		3		3
	$	1,513	$	1,579	$	2,087	$	2,169

The fair value of notes receivables 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 investments in lease obligation bonds are accounted for as held-to-maturity securities and the fair value is based on present value of the cash inflows based on the yield to maturity similar to the notes receivable. The maturities range from the 2007 to 2017.

The following table provides the amortized cost basis, unrealized gains and losses and fair values for the investments debt and equity securities above, which excludes the restricted funds and notes receivable:

	2006								2005
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	*(In millions)*
Debt securities	$	291	$	34	$	-	$	325	$	326	$	42	$	-	$	368
Equity securities		3		-		-		3		3		-		-		3
	$	294	$	34	$	-	$	328	$	329	$	42	$	-	$	371

There were no proceeds from the sale of investments, realized gains and losses on those sales, or interest and dividend income for the three years ended December 31, 2006 for the above investments:

(C) NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS-

Decommissioning trust investments are classified as available-for-sale. As part of the intra-system nuclear generation asset transfers in the fourth quarter of 2005, the Companies transferred their decommissioning trust investments to NGC with the exception of a portion related to OE?s leasehold interests in the nuclear generation assets retained by the Company. The Companies have no securities held for trading purposes. Upon adoption of FSP SFAS 115-1 and SFAS 124-1, the Company began expensing unrealized losses on available-for-sale securities held in the 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. Approximately $2 million of unrealized losses on available-for-sale securities were reclassified from OCI to earnings upon adoption of this pronouncement. The balance was determined using the specific identification method. The following table provides the carrying value, which equals the fair value of the nuclear decommissioning trust funds as of December 31, 2006 and 2005, respectively:

		2006		2005
Debt securities	*(In millions)*
?Government obligations		$	25	$	32
?Corporate debt securities			6		5
?Mortgage-backed securities			7		-
			38		37
Equity securities			80		67
		$	118	$	104

The following table summarizes the amortized cost basis, gross unrealized gains and losses and fair values for decommissioning trust investments as of December 31:

	2006								2005
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
		Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	*(In millions)*
Debt securities	$	38	$	-	$	-	$	38	$	37	$	-	$	-	$	37
Equity securities		61		19		-		80		61		9		3		67
	$	99	$	19	$	-	$	118	$	98	$	9	$	3	$	104

Proceeds from the sale of decommissioning trust investments, gross realized gains and losses on those sales, and interest and dividend income for the three years ended December 31, 200 6 were as follows:

	2006		2005		2004
	*(In millions)*
Proceeds from sales	$	39	$	227	$	154
Gross realized gains		1		35		25
Gross realized losses		1		7		7
Interest and dividend income		3		13		13

Unrealized gains applicable to the Company's decommissioning trusts are recognized in OCI in accordance with SFAS 115, as fluctuations in the fair value of these trust balances will eventually affect earnings.

6. LEASES:

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

The Company sold portions of its ownership interest 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. Subsequent to the intra-system generation assets transfers in the fourth quarter of 2005, the Company continues to be responsible during the terms of the leases, to the extent of its individual leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company has the right, at the end of the respective basic lease terms, to renew the leases for up to two years. The Company also has 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.

	2006		2005		2004
	*(In millions)*
Operating leases
Interest element	$	87.1	$	93.3	$	94.8
Other		57.5		52.3		50.4
Capital leases
Interest element		0.3		0.8		1.0
Other		1.3		1.9		1.6
Total rentals	$	146.2	$	148.3	$	147.8

The future minimum lease payments as of December 31, 2006, are:

			Operating Leases
					PNBV
	Capital		Lease		Capital
	Leases		Payments		Trusts		Net
	*(In millions)*
2007	$	0.1	$	146.1	$	59.9	$	86.2
2008		0.1		147.3		34.9		112.4
2009		0.1		147.6		42.1		105.5
2010		0.1		148.3		43.2		105.1
2011		0.1		147.3		42.7		104.6
Years thereafter		0.5		750.3		193.5		556.8
Total minimum lease payments		1.0	$	1,486.9	$	416.3	$	1,070.6
Executory costs		-
Net minimum lease payments		1.0
Interest portion		0.6
Present value of net minimum lease payments		0.4
Less current portion		0.1
Noncurrent portion	$	0.3

The Company invested in PNBV, which was established to purchase a portion of the lease obligation bonds issued on behalf of lessors in the Company?s Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. The PNBV arrangement effectively reduces lease costs related to those transactions. The Company 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.

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. FirstEnergy adopted FIN 46R for special-purpose entities as of December 31, 2003 and for all other entities in the first quarter of 2004. The Company consolidates a VIE when it is determined to be the VIE's primary beneficiary as defined by FIN 46R.

Included in the Company?s consolidated financial statements is PNBV, a VIE created in 1996 to refinance debt originally issued in connection with sale and leaseback transactions.

PNBV was established to purchase a portion of the lease obligation bonds issued in connection with the Company's 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. The Company used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a 3% equity interest by a unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of the Company.

Through its investment in PNBV, the Company has variable interests in certain owner trusts that acquired the interests in the Perry Plant and Beaver Valley Unit 2. The Company has concluded that it was not the primary beneficiary of the owner trusts and was therefore not required to consolidate these entities. The leases are accounted for as operating leases in accordance with GAAP.

The Company is exposed to losses under the sale-leaseback agreements upon the occurrence of certain contingent events that it considers unlikely to occur. The Company has a maximum exposure to loss under these provisions of $835 million, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the sale and leaseback agreement, the Company has net minimum discounted lease payments of $632 million that would not be payable if the casualty value payments are made.

8. OHIO TAX LEGISLATION:

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 will be computed consistent with the prior tax law, except that the tax liability as computed was or will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that were not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The increase to income taxes associated with the adjustment to net deferred taxes in 2005 was $32 million. Income tax expenses were reduced by $3 million during 2005 by the initial phase-out of the Ohio income-based franchise tax and phase-in of the CAT tax.

9. REGULATORY MATTERS:

Regulatory assets are costs which have been authorized by the PUCO and the FERC for recovery from customers in the future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered under the provisions of the Company?s transition plan.

The EPACT provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC?s review. On February 3, 2006, the FERC adopted a rule establishing certification requirements for the ERO, as well as regional entities envisioned to assume compliance monitoring and enforcement responsibility for the new reliability standards. The FERC issued an order on rehearing on March 30, 2006, providing certain clarifications and essentially affirming the rule.

The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC?s certification requirements for the ERO. The NERC made a filing with the FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC approval of pro forma delegation agreements with regional reliability organizations (regional entities). The new FERC rule referred to above, further provides for reorganizing regional entities that would replace the current regional councils and for rearranging their relationship with the ERO. The ?regional entity? may be delegated authority by the ERO, subject to FERC approval, for compliance and enforcement of reliability standards adopted by the ERO and approved by the FERC. The ERO filing was noticed on April 7, 2006 and comments and reply comments were filed in May, June and July 2006. On July 20, 2006, the FERC certified the NERC as the ERO to implement the provisions of Section 215 of the Federal Power Act and directed the NERC to make compliance filings addressing governance and non-governance issues and the regional delegation agreements. On September 18, 2006 and October 18, 2006, NERC submitted compliance filings addressing the governance and non-governance issues identified in the FERC ERO Certification Order, dated July 20, 2006. On October 30, 2006, the FERC issued an order accepting most of NERC?s governance filings. On January 18, 2007, the FERC issued an order largely accepting NERC?s compliance filings addressing non-governance issues, subject to an additional compliance filing requirement.

On April 4, 2006, NERC also submitted a filing with the FERC seeking approval of mandatory reliability standards, as well as for approval with the relevant Canadian authorities. These reliability standards are based, with some modifications and additions, on the current NERC Version 0 reliability standards. The reliability standards filing was subsequently evaluated by the FERC on May 11, 2006, leading to the FERC staff?s release of a preliminary assessment that cited many deficiencies in the proposed reliability standards. The NERC and industry participants filed comments in response to the Staff?s preliminary assessment. The FERC held a technical conference on the proposed reliability standards on July 6, 2006. The FERC issued a NOPR on the proposed reliability standards on October 20, 2006. In the NOPR, the FERC proposed to approve 83 of the 107 reliability standards and directed NERC to make technical improvements to 62 of the 83 standards approved. The 24 standards that were not approved remain pending at the FERC awaiting further clarification and filings by the NERC and regional entities. The FERC also provided additional clarification within the NOPR regarding the proposed application of final standards and guidance with regard to technical improvements of the standards. On November 15, 2006, NERC submitted several revised reliability standards and three new proposed reliability standards. Interested parties were provided the opportunity to comment on the NOPR (including the revised standards submitted by NERC in November) by January 3, 2007. Numerous parties, including FirstEnergy, filed comments on the NOPR on January 3, 2007. Mandatory reliability standards enforceable with penalties are expected to be in place by the summer of 2007. In a separate order issued October 24, 2006, the FERC approved NERC?s 2007 budget and business plan subject to certain compliance filings.

On November 29, 2006, NERC submitted an additional compliance filing with the FERC regarding the Compliance Monitoring and Enforcement Program (CMEP) along with the proposed Delegation Agreements between the ERO and the regional reliability entities.. The FERC provided opportunity for interested parties to comment on the CMEP by January 10, 2007. We, as well as other parties, moved to intervene and submitted responsive comments on January 10, 2007. This filing is pending before the FERC.

The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils completed the consolidation of these regions into a single new regional reliability organization known as Reliability First Corporation. Reliability First began operations as a regional reliability council under NERC on January 1, 2006 and on November 29, 2006 filed a proposed Delegation Agreement with NERC to obtain certification consistent with the final rule as a ?regional entity? under the ERO. All of FirstEnergy?s facilities are located within the Reliability First region.

FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the October 20, 2006 NOPR, it appears that the FERC will adopt more strict reliability standards than those contained in the current NERC standards. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates.. If FirstEnergy is unable to meet the reliability standards for its bulk power system in the future, it could have a material adverse effect on FirstEnergy?s and its subsidiaries? financial condition, results of operations and cash flows.

On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO?s concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio?s findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies? termination will be withdrawn and considered to be null and void. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court?s concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29 , 2007. I n their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. No further proceedings are scheduled at this time.

	Maintaining the existing level of base distribution rates through December 31, 2008 for the Company;

	Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;

	Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for the Company;

	Reducing the deferred shopping incentive balances as of January 1, 2006 by up to $75 million for the Company by accelerating the application of the Company's accumulated cost of removal regulatory liability; and

	Recovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all of TE?s and the Company?s distribution and transmission customers through a fuel recovery mechanism. The Company may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the amount collected through the fuel recovery mechanism.

	Recognize fuel and distribution deferrals commencing January 1, 2006;

	Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff;

	Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and

	Clarify that distribution expenditures do not have to be ?accelerated? in order to be deferred.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. On January 20, 2006, the OCC sought rehearing of the PUCO?s approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of the Ohio Companies' case with a similar case involving Dayton Power & Light Company. Oral arguments were heard on May 10, 2006. On November 29, 2006, the Ohio Supreme Court issued its opinion upholding the PUCO?s determination that the Ohio Companies may defer transmission and ancillary service related costs incurred on and after December 30, 2004. The Ohio Supreme Court also determined that the PUCO erred when it denied the OCC intervention, but further ruled that such error did not prejudice OCC and, therefore, the Ohio Supreme Court did not reverse or remand the PUCO on this ground. The Ohio Supreme Court also determined that the OCC?s appeal was not premature. No party filed a motion for reconsideration with the Ohio Supreme Court.

The terms of the settlement provide for modification of both the Ohio and Penn power supply agreements with FES. Under the Ohio power supply agreement, separate rates are established for the Ohio Companies? PLR requirements; special retail contract requirements, wholesale contract requirements, and interruptible buy-through retail load requirements. For their PLR and special retail contract requirements, the Ohio Companies will pay FES no more than the lower of (i) the sum of the retail generation charge, the rate stabilization charge, the fuel recovery mechanism charge, and FES? actual incremental fuel costs for such sales; or (ii) the wholesale price cap. Different wholesale price caps are imposed for PLR sales, special retail contracts, and wholesale contracts. The wholesale price for interruptible buy-through retail load requirements is limited to the actual spot price of power obtained by FES to provide this power. FES billed the Ohio Companies for the additional amount payable to FES for incremental fuel costs on power supplied during 2006. The total power supply cost billed by FES was lower in each case than the wholesale price caps specified in the settlement accepted by the FERC. In addition, pursuant to the settlement, the wholesale rate charged by FES under the Penn power supply agreement can be no greater than the generation component of charges for retail PLR load in Pennsylvania. The modifications to the Ohio and Pennsylvania power supply agreements became effective January 1, 2006. The Penn supply agreement subject to the settlement expired at midnight on December 31, 2006.

On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market. MISO contends that the filing will integrate operating reserves into MISO?s existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch. The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO. MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region. MISO is targeting implementation for the second or third quarter of 2008. The FERC has established March 23, 2007, as the date for interested parties to submit comments addressing the filing. The filing has not yet been fully evaluated to assess its impact on our operations.

10. CAPITALIZATION:

(A) RETAINED EARNINGS-

There are no restrictions on retained earnings for payment of cash dividends on the Company?s common stock.

(B) PREFERRED AND PREFERENCE STOCK-

The Company has eight million authorized and unissued shares of $25 par value preferred stock and eight million authorized and unissued shares of preference stock with no par value.

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

Other Long-term Debt-

Each of the Companies 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. The Company also has a 1998 general mortgage under which it issues mortgage bonds based upon the pledge of a like amount of FMB as security. These mortgage bonds therefore effectively enjoy the same lien on that property and are referred to as FMB herein. The Companies have various debt covenants under their respective financing arrangements. The most restrictive of their debt covenants relate to the nonpayment of interest and/or principal on debt which could trigger a default and the maintenance of minimum fixed charge ratios and debt to capitalization ratios. There also exists cross-default provisions among financing arrangements of FirstEnergy and the Companies.

Based on the amount of FMB authenticated by the respective mortgage bond trustees through December 31, 2006, the Companies? annual sinking fund requirements for all FMB issued under the various mortgage indentures amounts to $38 million. The Companies expect to deposit funds with their respective mortgage bond trustees in 2007 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 increases in the amount of the annual sinking fund requirement. The sinking fund required under the Company?s 1930 indenture is no longer required starting January 1, 2007, as this indenture has been satisfied.

Sinking fund requirements for FMB and maturing long-term debt (excluding capital leases) for the next five years are:

	*(In millions)*
2007	$	160
2008		179
2009		2
2010		65
2011		1

Included in the 2007 amount are $156 million for variable interest rate pollution control revenue bonds that have provisions by which individual debt holders are required to "put back" the respective debt to the issuer for redemption prior to its maturity date. This amount represents the next time the debt holders may exercise this provision.

The Companies' 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 $158 million and noncancelable municipal bond insurance policies of $123 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the LOCs or the policies, the Companies are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 1.7% of the amounts of the LOCs to the issuing bank and 0.214% to 0.230% of the amounts of the policies to the insurers and are obligated to reimburse the bank or insurers, as the case may be, for any drawings thereunder.

11. ASSET RETIREMENT OBLIGATIONS:

The Company has recognized legal obligations under SFAS 143 and FIN 47. SFAS 143 requires 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 amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the ARO increases, resulting in a period expense. Upon retirement, a gain or loss would be recognized if the cost to settle the retirement obligation differs from the carrying amount.

Pursuant to the generation asset transfers on October 24, 2005 and December 16, 2005, FGCO and NGC now own nearly all of the fossil and nuclear generation assets, respectively, previously owned by the Companies. The generating plant interests transferred do not include leasehold interests of the Company that are currently subject to sale and leaseback arrangements with non-affiliates (See Note 14). As a result, only the ARO associated with sale and leaseback arrangements remain with the Company.

In 2005, the Companies revised the ARO associated with Beaver Valley Unit 2 and Perry as a result of an updated decommissioning study. The present value of revisions in the estimated cash flows associated with projected decommissioning costs connected with the assets subject to sale and leaseback arrangements decreased the ARO and corresponding plant asset for Beaver Valley Unit 2 and Perry by $5 million and $6 million, respectively.

The Company continues to maintain the nuclear decommissioning trust funds associated with the sale and leaseback arrangements that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2006, the fair value of the decommissioning trust assets was $118 million.

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 it 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.

The Company identified applicable legal obligations as defined under the new standard at its retired generating units, substation control rooms, service center buildings, line shops and office buildings, identifying asbestos as the primary conditional ARO. As a result of adopting FIN 47 in December 2005, the Company recorded a conditional ARO liability of $27 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $9 million (recorded as part of the carrying amount of the related long-lived asset) and accumulated depreciation of $9 million. The Company recognized a regulatory liability of $1 million upon adoption of FIN 47 for the transition amounts related to establishing the ARO for asbestos removal from substation control room and service center buildings, therefore requiring a $26 million cumulative effect adjustment ($16 million net of tax) for unrecognized depreciation and accretion to be recorded as of December 31, 2005. The obligation to remediate asbestos, lead paint abatement and other remediation costs at the retired generating units was developed based on site specific studies performed by an independent engineer. The costs of remediation at the substation control rooms, service center buildings, line shops and office buildings were based on costs incurred during recent remediation projects performed at each of these locations, respectively. The conditional ARO liability was the developed utilizing an expected cash flow approach (as discussed in SFAC 7) to measure the fair value of the ARO. The Company used a probability weighted analysis to estimate when remediation payments would begin. The effect on income as if FIN 47 had been applied during 2004 is immaterial.

The following table describes the changes to the ARO balances during 2006 and 2005:

	2006		2005
ARO Reconciliation	*(In millions)*
Balance at beginning of year	$	83	$	339
Transfers to FGCO and NGC		-		(293	)
Accretion		5		21
Revisions in estimated cash flows		-		(11	)
FIN 47 ARO upon adoption		-		27
Balance at end of year	$	88	$	83

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

Short-term borrowings outstanding as of December 31, 200 6, consisted of $3 million of OE bank borrowings and $114 million of borrowings from affiliates. OES Capital is a wholly owned subsidiary of the Company whose borrowings are secured by customer accounts receivable purchased from the Company. OES Capital can borrow up to $170 million under a receivables financing arrangement at rates based on certain bank commercial paper and is required to pay an annual fee of 0.15% on the amount of the entire finance limit. The receivables financing agreement expires on December 5, 2007.. Penn Funding, a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. It can borrow up to $25 million under a receivables financing arrangement at rates based on bank commercial paper rates. The financing arrangements require payment of an annual facility fee of 0.13% on the entire finance limit. Penn's receivables financing agreements expire on June 28, 2007. As separate legal entities with separate creditors, OES Capital and Penn Funding would have to satisfy their separate obligations to creditors before any of their remaining assets could be made available to the Companies, respectively. As of December 31, 2006, both facilities were undrawn.

On August 24, 2006, FirstEnergy, the Companies, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a new $2.75 billion five-year revolving credit facility which replaced the prior $2 billion credit facility. Subject to specified conditions, FirstEnergy may request an increase in the total commitments available under the new facility up to a maximum of $3.25 billion. Commitments under the new facility are available until August 24, 2011, unless the lenders agree, at the request of the Borrowers, to two 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 sublimit, as well as applicable regulatory and other limitations. The Company?s borrowing limit under the facility is $500 million and Penn?s is $50 million, subject in each case to applicable regulatory approvals. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2006 and 2005 were 4.0% and 4.2%, respectively.

13. COMMITMENTS AND CONTINGENCIES:

(A) NUCLEAR INSURANCE-

The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.8 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its leasehold interests in Beaver Valley Unit 2 and the Perry Plant, the Company?s maximum potential assessment under the industry retrospective rating plan (assuming the other affiliate co-owners contribute their proportionate shares of any assessments under the retrospective rating plan) would be $34.4 million per incident but not more than $5.1 million in any one year for each incident.

The Company is also insured as to its respective leasehold interests in Beaver Valley Unit 2 and Perry under policies issued to NGC. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Company has also obtained approximately $167.8 million of insurance coverage for replacement power costs for its respective leasehold interests in Beaver Valley Unit 2 and Perry. Under these policies, the Company can be assessed a maximum of approximately $6.6 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.

The Company 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 the Company?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 the Company?s insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs.

(B) ENVIRONMENTAL MATTERS-

The Compan ies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in the Companies? determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

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 New Source Review litigation. This settlement agreement, which is in the form of a consent decree, was approved by the Court on July 11, 2005, and requires reductions of NO _X and SO ₂ emissions at the W. H. Sammis Plant and other 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 we fail to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, we could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation are currently estimated to be $1.5 billion ($400 million of which is expected to be spent in 2007, with the largest portion of the remaining $1.1 billion expected to be spent in 2008 and 2009).

The Sammis NSR Litigation consent decree also requires us 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 under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of SO ₂ emissions. FGCO also entered into an agreement with B&W on August 25, 2006 to supply flue gas desulfurization systems for the reduction of SO ₂ emissions. Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions also are being installed at the W.H. Sammis Plant under a 1999 agreement with B&W.

(C) OTHER LEGAL PROCEEDINGS-

Power Outages and Related Litigation

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy?s service area. The U.S. - Canada Power System Outage Task Force?s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy?s 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; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy?s Web site (www.doe.gov). We believe 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. We remain 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 proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

FirstEnergy companies also are defending five separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants?three in one case and four in the other?sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Three other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these three cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc., as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. On March 7, 2006, the PUCO issued a ruling, consolidating all of the pending outage cases for hearing; limiting the litigation to service-related claims by customers of the Ohio operating companies; dismissing FirstEnergy as a defendant; and ruling that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on October 16, 2007.

On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid to numerous insureds who allegedly suffered losses as a result of the August 14, 2003 outages. All of the insureds appear to be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006. On January 18, 2007, the Court granted the Companies? motion to dismiss the case. It is unknown whether or not the matter will be further appealed. No estimate of potential liability is available for any of these cases.

The Companies are vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on the Companies? financial condition, results of operations and cash flows.

Other Legal Matters

Various lawsuits, claims (including claims for asbestos exposure) and proceedings related to the Companies' normal business operations are pending against the Company and its subsidiaries. The most significant not otherwise discussed above are described herein.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the above matters, it could have a material adverse effect on the Companies? financial condition, results of operations and cash flows.

14. FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS:

On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy?s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred do not include OE?s leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, the Companies completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.

The difference (approximately $177.7 million) between the purchase price specified in the Master Facility Lease and the net book value at the date of transfer was credited to equity. FGCO also assumed certain assets and liabilities relating to the purchased units. As consideration, FGCO delivered to OE and Penn promissory notes of approximately $1.0 billion and $0.1 billion, respectively, that are secured by liens on the units purchased, bear interest at a rate per annum based on the weighted cost of OE?s and Penn's long-term debt (3.98% and 5.39%, respectively) and mature twenty years after the date of issuance. FGCO may pre-pay a portion of the promissory notes through refunding from time to time of OE?s and Penn's outstanding pollution control debt. The timing of any refunding will be subject to market conditions and other factors.

On December 16, 2005, the Companies completed the intra-system transfer of their respective ownership in the nuclear generation assets to NGC through an asset spin-off by way of dividend. FENOC continues to operate and maintain the nuclear generation assets.

The purchase price of the generation assets was the net book value as of September 30, 2005. The difference (approximately $20.5 million) between the purchase price and the net book value at the date of transfer was credited to equity. Pursuant to the OE Contribution Agreement, OE made a capital contribution to NGC of its undivided ownership interests in certain nuclear generation assets, the common stock of OES Nuclear Incorporated (OES Nuclear), a wholly owned subsidiary of OE that held an undivided interest in the Perry Nuclear Power Plant, together with associated decommissioning trust funds and other related assets. In connection with the contribution, NGC assumed other liabilities associated with the transferred assets. In addition, OE and Penn received promissory notes from NGC in the principal amount of approximately $371.5 million and $240.4 million, respectively, representing the net book value of the contributed assets as of September 30, 2005, less other liabilities assumed. The notes bear interest at a rate per annum based on OE?s and Penn's weighted average cost of long-term debt (3.98% and 5.39%, respectively), mature twenty years from the date of issuance, and are subject to prepayment at any time, in whole or in part, by NGC. Following the capital contribution, OES Nuclear was merged with and into NGC, and OE distributed the common stock of NGC as a dividend (approximately $106.8 million) to FirstEnergy, such that NGC is currently a direct wholly owned subsidiary of FirstEnergy. In December 2006, OE and Penn recorded a purchase price adjustment of $87.9 million for the nuclear generation asset transfer to adjust intercompany notes and equity accounts to reflect a change in the agreed upon value for the asset retirement obligations that were assumed by NGC.

These transactions were pursuant to the Ohio Companies? and Penn?s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.

The transfers are expected to affect the Companies' near-term future results with reductions in revenues and expenses. Revenues will be reduced due to the termination of the sale of the Companies' nuclear-generated KWH and the lease of their non-nuclear generation assets arrangements with FES. The Companies' expenses will be lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets. OE will retain the nuclear-generated KWH sales arrangement and the portion of expenses related to its retained leasehold interests in Perry and Beaver Valley Unit 2. In addition, the Companies will receive interest income from associated company notes receivable from FGCO and NGC for the transfer of their generation net assets and eliminate the interest expense on certain pollution control notes to be transferred to FGCO and NGC. FES will continue to provide the PLR requirements of the Company under revised purchased power arrangements for a three-year period beginning January 1, 2006 (see Note 9 - Regulatory Matters).

The following table provides the value of assets transferred in 2005 along with the related liabilities:



Assets Transferred (In millions)

Property, plant and equipment	$	1,592
Other property and investments		372
Current assets		94
Deferred charges		-
	$	2,058

Liabilities Related to Assets Transferred

Long-term debt	$	104
Current liabilities		-
Noncurrent liabilities		261
	$	365

Net Assets Transferred	$	1,693

15. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:

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

In February 2007, FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value. The Standard requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the 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, Fair Value Measurements, and SFAS 107, Disclosures about Fair Value of Financial Instruments. The Companies are currently evaluating the impact of this Statement on their financial statements.

SFAS 157 - ?Fair Value Measurements?

This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The Companies are currently evaluating the impact of this Statement on their financial statements.

FIN 48 - ?Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109?

In June 2006, the FASB issued FIN 48 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise?s financial statements in accordance with FASB Statement No. 109, ?Accounting for Income Taxes.? This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation will be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit to recognize in the financial statements. This interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact of this Statement. The Companies do not expect this Statement to have a material impact on their financial statements.

16. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):

The following summarizes certain consolidated operating results by quarter for 200 6 and 2005:

Three Months Ended	March 31, 2006		June 30, 2006		September 30, 2006		December 31, 2006
	*(In millions)*
Revenues	$	582.2	$	573.1	$	673.7	$	594.5

Expenses		499.4		493.8		622.9		520.3
Operating Income		86.8		79.3		50.8		74.2
Other Income		15.3		14.9		10.6		3.0
Income Before Income Taxes		102.1		94.2		61.4		77.2
Income Taxes		38.3		35.0		17.9		32.1
Net Income	$	63.8	$	59.2	$	43.5	$	45.1
Earnings on Common Stock	$	63.2	$	55.6	$	43.4	$	44.8

Three Months Ended	March 31, 2005			June 30, 2005		September 30, 2005		December 31, 2005
	*(In millions)*
Revenues	$	726.3		$	716.6	$	825.8	$	706.8
Expenses		598.3			576.1		600.4		568.2
Operating Income		128.0			140.5		225.4		138.6
Other Income (Expense)		(17.8	)		1.2		11.3		13.1
Income Before Income Taxes		110.2			141.7		236.7		151.7
Income Taxes		53.4			94.6		105.3		56.6
Income Before Cumulative Effect of a Change in Accounting Principle		56.8			47.1		131.4		95.1
Cumulative Effect of a Change in Accounting Principle (Net of Income Taxes) (Note 2(G))		-			-		-		16.3
Net Income	$	56.8		$	47.1	$	131.4	$	78.8
Earnings on Common Stock	$	56.1		$	46.4	$	130.7	$	78.1

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

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
The Cleveland Electric Illuminating Company	9% Cumulative Trust Preferred Securities, $25 per preferred security	New York Stock Exchange

Yes (X) No ( )	FirstEnergy Corp.
Yes ( ) No (X)	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 ( )	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)	FirstEnergy Corp.

( )	FirstEnergy Corp.
(X)	Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company.

Large Accelerated Filer (X)	FirstEnergy Corp.
Accelerated Filer ( )	N/A
Non-accelerated Filer (X)	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 27, 2007

FirstEnergy Corp., $0.10 par value		319,205,517
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		15,009,335
Metropolitan Edison Company, no par value		859,500
Pennsylvania Electric Company, $20 par value		5,290,596

		PART OF FORM 10-K INTO WHICH
DOCUMENT		DOCUMENT IS INCORPORATED

FirstEnergy Corp. Annual Report to Stockholders for
the fiscal year ended December 31, 2006 (Pages 3-104)		Part II

Proxy Statement for 2007 Annual Meeting of Stockholders
to be held May 15, 2007		Part III

NYSE	New York Stock Exchange
OCC	Ohio Consumers' Counsel
OVEC	Ohio Valley Electric Corporation
PJM	PJM Interconnection L.L.C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RFP	Request For Proposal
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 101	SFAS No. 101, "Accounting for Discontinuation of Application of SFAS 71"
SFAS 144	SFAS No. 144, "Accounting for the Impairment of Disposal of Long-Lived Assets"
SO ₂	Sulfur Dioxide
TMI-2	Three Mile Island Unit 2

	Page
Part I
Item 1. Business	1
The Company	1
Generation Asset Transfers	2
Divestitures	2
Utility Regulation	2
Regulatory Accounting	3
Reliability Initiatives	3
PUCO Rate Matters	5
PPUC Rate Matters	6
NJBPU Rate Matters	8
FERC Rate Matters	10
Capital Requirements	11
Nuclear Regulation	14
Nuclear Insurance	14
Environmental Matters	15
Clean Air Act Compliance	15
National Ambient Air Quality Standards	16
Mercury Emissions	16
W. H. Sammis Plant	17
Climate Change	17
Clean Water Act	17
Regulation of Hazardous Waste	18
Fuel Supply	18
System Capacity and Reserves	19
Regional Reliability	19
Competition	19
Research and Development	20
Executive Officers	21
Employees	22
FirstEnergy Website	22

Item 1A. Risk Factors	22

Item 1B. Unresolved Staff Comments	30

Item 2. Properties	30

Item 3. Legal Proceedings	32

Item 4. Submission of Matters to a Vote of Security Holders	32

Part II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities	32

Item 6. Selected Financial Data	33

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	33

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	33

Item 8. Financial Statements and Supplementary Data	33

Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	33

Item 9A. Controls and Procedures	33

Item 9B. Other Information	34

Part III
Item 10. Directors and Executive Officers of the Registrant	34

Item 11. Executive Compensation	35

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	35

Item 13. Certain Relationships and Related Transactions	35

Item 14. Principal Accounting Fees and Services	35

Part IV
Item 15. Exhibits, Financial Statement Schedules	36

	2006		Capital Expenditures Forecast
	Actual		2007		2008-2011		Total
	*(In millions)*
OE	$	105	$	120	$	544	$	664
Penn		19		26		86		112
CEI		127		158		683		841
TE		61		64		261		325
JCP&L		160		192		1,144		1,336
Met-Ed		85		83		428		511
Penelec		111		92		522		614
ATSI		39		46		296		342
FGCO		213		445		1,712		2,157
NGC		204		126		534		660
Other subsidiaries		46		91		239		330
Total	$	1,170	$	1,443	$	6,449	$	7,892

	Long-Term Debt Redemption Schedule
	2007		2008-2011		Total
	*(In millions)*

OE	$	3	$	180	$	183
Penn*		1		4		5
CEI**		120		275		395
TE		30		-		30
JCP&L		33		119		152
Met-Ed		50		100		150
Penelec		-		159		159
FirstEnergy		-		1,500		1,500
Other subsidiaries		4		25		29
Total	$	241	$	2,362	$	2,603

* Penn has an additional $63 million due to associated companies in 2008-2011.
** CEI has an additional $65 million due to associated companies in 2008-2011.

	Net Operating Lease Commitments
	2007		2008-2011		Total
	*(In millions)*
OE	$	86	$	428	$	514
CEI		14		52		66
TE		79		291		370
JCP&L		8		32		40
Met-Ed		4		16		20
Penelec		5		16		21
FESC		8		31		39
Total	$	204	$	866	$	1,070

Name	Age	Position Held During Past Five Years	Dates

A. J. Alexander (A)(B)	55	President and Chief Executive Officer	2004-present
		President and Chief Operating Officer	*-2004

L. M. Cavalier	55	Senior Vice President - Human Resources	2005-present
		Vice President - Human Resources	*-2005

M. T. Clark	56	Senior Vice President - Strategic Planning & Operations	2004-present
		Vice President - Business Development	*-2004

K. W. Dindo	57	Vice President and Chief Risk Officer	*-present

D. S. Elliott (B)	52	President - Pennsylvania Operations	2005-present
		Senior Vice President	*-2005

R. R. Grigg (A)(B)	58	Executive Vice President and Chief Operating Officer	2004-present
		President and Chief Executive Officer - WE Generation Executive Vice President - WEC	2003-2004 *-2003

A. Jamshidi C. E. Jones (A)(B)	52 51	Vice President - Commodity Operations (FES) Vice President - Energy Delivery Vice President & Chief Information Officer Senior Vice President - Energy Delivery & Customer Service Regional Vice President - Operations	2006-present 2004-2006 -2004 2003-present -2003

C. D. Lasky	44	Vice President - Fossil Operations (FES)	2004-present
		Plant Director	2003-2004
		Assistant Plant Director	*-2003

G. R. Leidich	56	President and Chief Nuclear Officer - FENOC	2003-present
		Executive Vice President - FENOC	2002-2003
		Executive Vice President - Institute of Nuclear Power Ops	*-2002

D. C. Luff	59	Senior Vice President - Governmental Affairs	2005-present
		Vice President	*-2005

R. H. Marsh (A)(B)(C)	56	Senior Vice President and Chief Financial Officer	*-present

S. E. Morgan (C)	56	President - JCP&L	2004-present
		Vice President - Energy Delivery	2002-2004
		Regional President - Central	*-2002

J. M. Murray (A)	60	President - Ohio Operations Regional President - West	2005-present *-2005

J. F. Pearson (A)(B)(C)	52	Vice President and Treasurer	2006-present
		Treasurer Group Controller - Strategic Planning and Operations	2005-2006 2004-2005
		Group Controller - FES	2003-2004
		Director - FES	*-2003

G. L. Pipitone	56	President - FES	2004-present
		Senior Vice President	*-2004

D. R. Schneider	45	Vice President - Energy Delivery Vice President - Commodity Operations (FES)	2006-present 2004-2006
		Vice President - Fossil Operations (FES)	*-2004

C. B. Snyder	61	Senior Vice President	*-present

L.L. Vespoli (A)(B)(C)	47	Senior Vice President and General Counsel	*-present

H. L. Wagner (A)(B)(C)	54	Vice President, Controller and Chief Accounting Officer	*-present

T. M. Welsh	57	Senior Vice President - External Affairs	2004-present
		Vice President - Communications	*-2004

FESC	2,991
OE	1,234
CEI	943
TE	420
Penn	198
JCP&L	1,448
Met-Ed	701
Penelec	888
ATSI	36
FES	2,082
FENOC	2,798
Total	13,739

		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	800 (c)

W. H. Sammis-	1-6	1,620
Stratton, OH	7	600
Kyger Creek - Chesire, OH	1-5	210 (d)
Clifty Creek - Madison, IN	1-6	253 (d)
Total		7,902

Nuclear Units
Beaver Valley-	1	868
Shippingport, PA	2	854 (e)
Davis-Besse-
Oak Harbor, OH	1	898
Perry-
N. Perry Village, OH	1	1,258 (f)
Total		3,878

Oil/Gas-Fired/
Pumped Storage Units
Richland-Defiance, OH	1-3	42
	4-6	390
Seneca-Warren, PA	1-3	443
Sumpter-Sumpter Twp, MI	1-4	340

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

OE	30,008	550	8,298,000
Penn	5,756	44	1,739,000
CEI	25,130	2,144	9,301,000
TE	1,851	223	3,677,000
JCP&L	18,966	2,135	20,964,000
Met-Ed	14,751	1,407	9,848,000
Penelec	20,007	2,690	14,190,000
ATSI*	-	5,816	22,931,000
Total	116,469	15,009	90,948,000

·	changing weather conditions or seasonality;

·	changes in electricity usage by our customers;

·	liquidity 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 sabatage, terrorist acts, embargeos and other catastrophic events.

Notes:	(a)	Includes CEI's leasehold interest in Bruce Mansfield Unit 1 of 6.50% (54 MW).
	(b)	Includes CEI's and TE's leasehold interests in Bruce Mansfield Unit 2 of 28.6% (237 MW) and 17.30% (144 MW), respectively.
	(c)	Includes CEI's and TE's leasehold interests in Bruce Mansfield Unit 3 of 24.47% (196 MW) and 19.91% (159 MW), respectively.
	(d )	Represents FGCO's 20.5% entitlement based on FirstEnergy's participation in OVEC.
	(e)	Includes OE's and TE's leasehold interests in Beaver Valley Unit 2 of 21.66% (185 MW) and 18.26% (156 MW), respectively.
	(f)	Includes OE's leasehold interest in Perry of 12.58% (158 MW).
	(g)	Represents JCP&L's 50% ownership interest.

	Period
	October 1-31, 2006	November 1-30, 2006	December 1-31, 2006	Fourth Quarter
Total Number Of Shares Purchased ^(a)	234,384	76,844	331,411	642,639
Average Price Paid per Share	$58.02	$58.90	$60.58	$59.45
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 ^(b)	1,369,241	1,369,241	1,369,241	1,369,241

	Item 6	Item 7	Item 7A	Item 8

FirstEnergy	3	5-51	29-32	52-105
OE	2	3-20	11-12	21-49
CEI	2	3-19	11	20-46
TE	2	3-19	11	20-45
JCP&L	2	3-15	7-9	16-40
Met-Ed	2	3-14	7-9	15-37
Penelec	2	3-14	7-9	15-37

	Audit Fees ⁽¹⁾				Audit-Related Fees
Company	2006		2005		2006		2005
	*(In thousands)*
OE	$	1,495	$	1,492	$	-	$	-
CEI		726		755		-		-
TE		643		610		-		-
JCP&L		816		728		-		-
Met-Ed		576		597		-		-
Penelec		576		605		-		-
Other subsidiaries		1,478		1,786		-		-

Total FirstEnergy	$	6,310	$	6,573	$	-	$	-

	First- Energy	OE	CEI	TE	JCP&L	Met-Ed	Penelec


Management Reports	1	-	-	-	-	-	-
Report of Independent Registered Public Accounting Firm	2	1	1	1	1	1	1
Statements of Income-Three Years Ended December 31, 2006	52	21	20	20	16	15	15
Balance Sheets-December 31, 2006 and 2005	53	22	21	21	17	16	16
Statements of Capitalization-December 31, 2006 and 2005	54-55	23-24	22	22	18	17	17
Statements of Common Stockholders' Equity-Three Years Ended December 31, 2006	56	25	23	23	19	18	18
Statements of Preferred Stock-Three Years Ended December 31, 2006	57	25	23	23	19	-	-
Statements of Cash Flows-Three Years Ended December 31, 2006	58	26	24	24	20	19	19
Statements of Taxes-Three Years Ended December 31, 2006		27	25	25	21	20	20
Notes to Financial Statements	59-105	28-49	26-46	26-45	22-40	21-37	21-37

	First - Energy	OE	CEI	TE	JCP&L	Met-Ed	Penelec


Report of Independent Registered Public Accounting Firm	71	72	73	74	75	76	77

Schedule - Three Years Ended December 31, 2006: II - Consolidated Valuation and Qualifying Accounts	78	79	80	81	82	83	84

3-1	Articles of Incorporation constituting FirstEnergy Corp.'s Articles of Incorporation, dated September 17, 1996. (September 17, 1996 Form 8-K, Exhibit C)

3-1(a)	Amended Articles of Incorporation of FirstEnergy Corp. (Registration No. 333-21011, Exhibit (3)-1)

3-2	Regulations of FirstEnergy Corp. (September 17, 1996 Form 8-K, Exhibit D)

3-2(a)	FirstEnergy Corp. Amended Code of Regulations. (Registration No. 333-21011, Exhibit (3)-2)

4-1	Rights Agreement (December 1, 1997 Form 8-K, Exhibit 4.1)

4-2	FirstEnergy Corp. to The Bank of New York, Supplemental Indenture, dated November 7, 2001. (2001 Form 10-K, Exhibit 4-2)

(C)10-1	FirstEnergy Corp. Executive and Director Incentive Compensation Plan, revised November 15, 1999. (1999 Form 10-K, Exhibit 10-1)

(C)10-2	Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, revised November 15, 1999. (1999 Form 10-K, Exhibit 10-2)

(C)10-3	Form of Employment, severance and change of control agreement between FirstEnergy Corp. and the following executive officers: L.L. Vespoli, C.B. Snyder, and R.H. Marsh, through December 31, 2005. (1999 Form 10-K, Exhibit 10-3)


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

(C)10-5	FirstEnergy Corp. Executive Incentive Compensation Plan. (1999 Form 10-K, Exhibit 10-5)

(C)10-6	Restricted stock agreement between FirstEnergy Corp. and A. J. Alexander. (1999 Form 10-K, Exhibit 10-6)

(C)10-7	FirstEnergy Corp. Executive and Director Incentive Compensation Plan. (1998 Form 10-K, Exhibit 10-1)

(C)10-8	Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, amended February 15, 1999. (1998 Form 10-K, Exhibit 10-2)

(C)10-9	Restricted Stock Agreement between FirstEnergy Corp. and A. J. Alexander. (2000 Form 10-K, Exhibit 10-1)

(C)10-10	Restricted Stock Agreement between FirstEnergy Corp. and H. P. Burg. (2000 Form 10-K, Exhibit 10-2)

(C)10-11	Stock Option Agreement between FirstEnergy Corp. and officers dated November 22, 2000. (2000 Form 10-K, Exhibit 10-3)

(C)10-12	Stock Option Agreement between FirstEnergy Corp. and officers dated March 1, 2000. (2000 Form 10-K, Exhibit 10-4)

(C)10-13	Stock Option Agreement between FirstEnergy Corp. and director dated January 1, 2000. (2000 Form 10-K, Exhibit 10-5)

(C)10-14	Stock Option Agreement between FirstEnergy Corp. and two directors dated January 1, 2001. (2000 Form 10-K, Exhibit 10-6)

(C)10-15	Executive and Director Incentive Compensation Plan dated May 15, 2001. (2001 Form 10-K, Exhibit 10-1)

(C)10-16	Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, revised September 18, 2000. (2001 Form 10-K, Exhibit 10-2)

(C)10-17	Stock Option Agreements between FirstEnergy Corp. and Officers dated May 16, 2001. (2001 Form 10-K, Exhibit 10-3)

(C)10-18	Form of Restricted Stock Agreements between FirstEnergy Corp. and Officers. (2001 Form 10-K, Exhibit 10-4)

(C)10-19	Stock Option Agreements between FirstEnergy Corp. and One Director dated January 1, 2002. (2001 Form 10-K, Exhibit 10-5)

(C)10-20	FirstEnergy Corp. Executive Deferred Compensation Plan. (2001 Form 10-K, Exhibit 10-6)

(C)10-21	Executive Incentive Compensation Plan-Tier 2. (2001 Form 10-K, Exhibit 10-7)

(C)10-22	Executive Incentive Compensation Plan-Tier 3. (2001 Form 10-K, Exhibit 10-8)

(C)10-23	Executive Incentive Compensation Plan-Tier 4. (2001 Form 10-K, Exhibit 10-9)

(C)10-24	Executive Incentive Compensation Plan-Tier 5. (2001 Form 10-K, Exhibit 10-10)

(C)10-25	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)

(C)10-26	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)

(C)10-27	GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group, Inc. Employees. (2001 Form 10-K, Exhibit 10-13)


(C)10-28	Executive and Director Stock Option Agreement dated June 11, 2002. (2002 Form 10-K, Exhibit 10-1)

(C)10-29	Director Stock Option Agreement. (2002 Form 10-K, Exhibit 10-2)

(C)10-30	Executive and Director Executive Incentive Compensation Plan, Amendment dated May 21, 2002. (2002 Form 10-K, Exhibit 10-3)

(C)10-31	Directors Deferred Compensation Plan, Revised Nov. 19, 2002. (2002 Form 10-K, Exhibit 10-4)

(C)10-32	Executive Incentive Compensation Plan 2002. (2002 Form 10-K, Exhibit 10-5)

(C)10-33	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.)

(C)10-34	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.)

(C)10-35	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.)

(C)10-36	Form of 2000 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (2000 Form 10-K, Exhibit 10-W, File No. 1-6047, GPU, Inc.)

(C)10-37	Deferred Remuneration Plan for Outside Directors of GPU, Inc. as amended and restated effective August 8, 2000. (2000 Form 10-K, Exhibit 10-O, File No. 1-6047, GPU, Inc.)

(C)10-38	Retirement Plan for Outside Directors of GPU, Inc. as amended and restated as of August 8, 2000. (2000 Form 10-K, Exhibit 10-N, File No. 1-6047, GPU, Inc.)

(C)10-39	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.)

(C)10-40	Deferred Compensation Plan for Outside Directors, effective November 7, 2001. (Exhibit 4(f), Form S-8, File No. 333-101472)

(C)10-41	Employment Agreement between FirstEnergy and an officer dated July 20, 2004. (September 30, 2004 Form 10-Q, Exhibit 10-41)

(C)10-42	Stock Option Agreement between FirstEnergy and an officer dated August 20, 2004. (September 30, 2004 Form 10-Q, Exhibit 10-42)

(C)10-43	Restricted Stock Agreement between FirstEnergy and an officer dated August 20, 2004. (September 30, 2004 Form 10-Q, Exhibit 10-43)

(C)10-44	Executive Bonus Plan between FirstEnergy and Officers dated October 31, 2004. (September 30, 2004 Form 10-Q, Exhibit 10-44)

(C)10-45	Form of Employment, Severance, and Change of Control Agreement, between FirstEnergy and A. J. Alexander. (2004 Form 10-K, Exhibit 10-12)

(C)10-46	Form of Employment, Severance, and Change of Control Agreement, Tier 1, between FirstEnergy and the following executive officers: C.B. Snyder, L.L. Vespoli, and R.H. Marsh (effective January 1, 2006). (2004 Form 10-K, Exhibit 10-13)

(C)10-47	Form of Employment, Severance, and Change of Control Agreement, Tier 1, between FirstEnergy and the following executive officers: L.M. Cavalier, M.T. Clark, and R.R. Grigg. (2004 Form 10-K, Exhibit 10-14)

(C)10-48	Form of Employment, Severance, and Change of Control Agreement, Tier 2, between FirstEnergy and the following executive officers: K.J. Keough and K.W. Dindo (effective January 1, 2006). (2004 Form 10-K, Exhibit 10-15)


(C)10-49	Form of Employment, Severance, and Change of Control Agreement, Tier 2, between FirstEnergy and G. L. Pipitone. (2004 Form 10-K, Exhibit 10-16)

(C)10-50	Executive and Director Incentive Compensation Plan, Amendment dated January 18, 2005. (2004 Form 10-K, Exhibit 10-3)

(C)10-51	Form of Restricted Stock Agreements, between FirstEnergy and Officers. (2004 Form 10-K, Exhibit 10-4)

(C)10-52	Form of Restricted Stock Unit Agreements (Performance Adjusted), between FirstEnergy and Officers. (2004 Form 10-K, Exhibit 10-5)

(C)10-53	Form of Restricted Stock Agreement, between FirstEnergy and an officer. (2004 Form 10-K, Exhibit 10-6)

10-54	Notice of Termination Tolling Agreement, Restated Partial Requirements Agreement (September 2005 10-Q, Exhibit 10-1)

10-55	Agreement by and between FirstEnergy Generation Corp. and Bechtel Power Corporation dated August 26, 2005. (September 2005 10-Q, Exhibit 10-2)

10-56	Consent Decree dated as of March 18, 2005. (Form 8-K dated March 18, 2005, Exhibit 10-1.)

10-57	Deferred Prosecution Agreement entered into January 20, 2006 among FirstEnergy Nuclear Operating Company, U.S. Attorney's Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the Department of Justice. (Form 8-K dated January 20, 2006, Exhibit 99-2)

(D)10-58	Form of Guaranty Agreement dated as of December 16, 2005 between FirstEnergy Corp. and FirstEnergy Solutions Corp. in Favor of Barclays Bank PLC as Adminstrative Agent for the Banks. (2005 Form 10-K, Exhibit 10-1)

(D)10-59	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 10-3)

10-60	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 10-5)

10-61	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 10-8)

(D)10-62	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 10-2)

(D)10-63	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 10-4)

10-64	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 10-6)

10-65	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 10-7)

10-66	Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and the FirstEnergy Operating Companies - OE, CEI and TE (Buyers) (2005 Form 10-K, Exhibit 10-9)

10-67	Electric Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and Pennsylvania Power Company (Buyer). (2005 Form 10-K, Exhibit 10-10)

(E)10-68	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 10-Q, Exhibit 10-1)

(E)10-69	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 10-Q, Exhibit 10-2)

(E)10-70	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 10-Q, Exhibit 10-3)

(E)10-71	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 10-Q, Exhibit 10-4)

(C)10-72	Form of Restricted Stock Agreement between FirstEnergy and A. J. Alexander, dated February 27, 2006. (March 2006 10-Q, Exhibit 10-6)

(C)10-73	Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy and A.J. Alexander, dated March 1, 2006. (March 2006 10-Q, Exhibit 10-7)

(C)10-74	Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy and named executive officers, dated March 1, 2006. (March 2006 10-Q, Exhibit 10-8)

(C)10-75	Form of Restricted Stock Unit Agreement (Discretionary) between FirstEnergy and R.H. Marsh, dated March 1, 2006. (March 2006 10-Q, Exhibit 10-9)

10-76	Confirmation dated August 9, 2006 between FirstEnergy Corp and JP Morgan Chase Bank National Association (September 2006 10-Q, Exhibit 10-1)

(A)(F)10-77	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) (Form 8-K dated December 5, 2006)

(A)(G)10-78	Form of Supplemental Letter of Credit Agreement, dated as of December 5, 2006 among FirstEnergy Corp., FirstEnergy Generation Corp. and Barclays Bank PLC, as Fronting Bank (FirstEnergy Generation Corp. Project) (Form 8-K dated December 5, 2006)

(A)10-79	Form of Letter of Credit and Reimbursement Agreement dated as of December 28, 2006 among FirstEnergy Corp., as Obligor, The Lenders Named Herein, as Lender, and Wachovia Fixed Income Structured Trading Solutions, LLC as Administrative Agent and as Fronting Bank (Form 8-K dated December 5, 2006)

(A)(F)10-80	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. (Form 8-K dated December 5, 2006)

(A)(C)10-81	Amendment to Employment Agreement for Richard R. Grigg dated January 16, 2007. (Form 8-K dated January 16, 2007)

(A)12.1	Consolidated fixed charge ratios.

(A)13	FirstEnergy 2006 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, 2006.

(A)23	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. Section 1350.

(A)	Provided herein in electronic format as an exhibit.

(C)	Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.


(D)	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.

(E)	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.

(F)	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.

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

2-1	Agreement and Plan of Merger, dated as of September 13, 1996, between Ohio Edison Company (OE) and Centerior Energy Corporation. (September 17, 1996 Form 8-K, Exhibit 2-1)

3-1	Amended Articles of Incorporation, Effective June 21, 1994, constituting OE's Articles of Incorporation. (1994 Form 10-K, Exhibit 3-1).

3-2	Amendment to Articles of Incorporation, Effective November 12, 1999 (2004 Form 10-K, Exhibit 3-2).

3-3	Amended and Restated Code of Regulations, amended March 15, 2002. (2001 Form 10-K, Exhibit 3-2).

(B)4-1	Indenture dated as of August 1, 1930 between OE and Bankers Trust Company (now the Bank of New York), as Trustee, as amended and supplemented by Supplemental Indentures:

		Incorporated by
		Reference to
Dated as of	File Reference	Exhibit No.
March 3, 1931	2-1725	B1, B-1(a),B-1(b)
November 1, 1935	2-2721	B-4
January 1, 1937	2-3402	B-5
September 1, 1937	Form 8-A	B-6
June 13, 1939	2-5462	7(a)-7
August 1, 1974	Form 8-A, August 28, 1974	2(b)
July 1, 1976	Form 8-A, July 28, 1976	2(b)
December 1, 1976	Form 8-A, December 15, 1976	2(b)
June 15, 1977	Form 8-A, June 27, 1977	2(b)

*Supplemental Indentures:*
September 1, 1944	2-61146	2(b)(2)
April 1, 1945	2-61146	2(b)(2)
September 1, 1948	2-61146	2(b)(2)
May 1, 1950	2-61146	2(b)(2)
January 1, 1954	2-61146	2(b)(2)
May 1, 1955	2-61146	2(b)(2)
August 1, 1956	2-61146	2(b)(2)
March 1, 1958	2-61146	2(b)(2)
April 1, 1959	2-61146	2(b)(2)
June 1, 1961	2-61146	2(b)(2)
September 1, 1969	2-34351	2(b)(2)
May 1, 1970	2-37146	2(b)(2)
September 1, 1970	2-38172	2(b)(2)
June 1, 1971	2-40379	2(b)(2)
August 1, 1972	2-44803	2(b)(2)
September 1, 1973	2-48867	2(b)(2)
May 15, 1978	2-66957	2(b)(4)
February 1, 1980	2-66957	2(b)(5)
		Incorporated by
		Reference to
Dated as of	File Reference	Exhibit No.
April 15, 1980	2-66957	2(b)(6)
June 15, 1980	2-68023	(b)(4)(b)(5)
October 1, 1981	2-74059	(4)(d)
October 15, 1981	2-75917	(4)(e)
February 15, 1982	2-75917	(4)(e)
July 1, 1982	2-89360	(4)(d)
March 1, 1983	2-89360	(4)(e)
March 1, 1984	2-89360	(4)(f)
September 15, 1984	2-92918	(4)(d)
September 27, 1984	33-2576	(4)(d)
November 8, 1984	33-2576	(4)(d)
December 1, 1984	33-2576	(4)(d)
December 5, 1984	33-2576	(4)(e)
January 30, 1985	33-2576	(4)(e)
February 25, 1985	33-2576	(4)(e)
July 1, 1985	33-2576	(4)(e)
October 1, 1985	33-2576	(4)(e)
January 15, 1986	33-8791	(4)(d)
May 20, 1986	33-8791	(4)(d)
June 3, 1986	33-8791	(4)(e)
October 1, 1986	33-29827	(4)(d)
August 25, 1989	33-34663	(4)(d)
February 15, 1991	33-39713	(4)(d)
May 1, 1991	33-45751	(4)(d)
May 15, 1991	33-45751	(4)(d)
September 15, 1991	33-45751	(4)(d)
April 1, 1992	33-48931	(4)(d)
June 15, 1992	33-48931	(4)(d)
September 15, 1992	33-48931	(4)(e)
April 1, 1993	33-51139	(4)(d)

June 15, 1993		33-51139	(4)(d)
September 15, 1993		33-51139	(4)(d)
November 15, 1993		1-2578	(4)(2)
April 1, 1995		1-2578	(4)(2)
May 1, 1995		1-2578	(4)(2)
July 1, 1995		1-2578	(4)(2)
June 1, 1997		1-2578	(4)(2)
April 1, 1998		1-2578	(4)(2)
June 1, 1998		1-2578	(4)(2)
September 29, 1999		1-2578	(4)(2)
April 1, 2000		1-2578	(4)(2)(a)
April 1, 2000		1-2578	(4)(2)(b)
June 1, 2001		1-2578
February 1, 2003		1-2578	4(2)
March 1, 2003		1-2578	4(2)
August 1, 2003		1-2578	4(2)
June 1, 2004		1-2578	4(2)
June 1, 2004		1-2578	4(2)
December 1, 2004		1-2578	4(2)
April 1, 2005		1-2578	4(2)
April 15, 2005		1-2578	4(2)
June 1, 2005		1-2578	4(2)

(B) 4-2	General Mortgage Indenture and Deed of Trust dated as of January 1, 1998 between OE and the Bank of New York, as Trustee, as amended and supplemented by Supplemental Indentures; (Registration No. 333-05277, Exhibit 4(g)).

4-3	Indenture dated as of April 1, 2003 between OE and The Bank of New York, as Trustee.

4-4	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 dated June 26, 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	Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(3))

10-4	Amendment No. 1 dated as of January 1, 1993 to Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (1993 Form 10-K, Exhibit 10-4)

10-5	Agreement for the Termination or Construction of Certain Agreements effective September 1, 1980 among the CAPCO Group. (Registration No. 2-68906, Exhibit 10-4)

10-6	Amendment dated as of December 23, 1993 to Agreement for the Termination or Construction of Certain Agreements effective September 1, 1980 among the CAPCO Group. (1993 Form 10-K, Exhibit 10-6)

10-7	CAPCO Basic Operating Agreement, as amended September 1, 1980. (Registration No. 2-68906, Exhibit 10-5)


10-8	Amendment No. 1 dated August 1, 1981, and Amendment No. 2 dated September 1, 1982 to CAPCO Basic Operating Agreement, as amended September 1, 1980. (September 30, 1981 Form 10-Q, Exhibit 20-1 and 1982 Form 10-K, Exhibit 19-3, respectively)

10-9	Amendment No. 3 dated July 1, 1984 to CAPCO Basic Operating Agreement, as amended September 1, 1980. (1985 Form 10-K, Exhibit 10-7)

10-10	Basic Operating Agreement between the CAPCO Companies as amended October 1, 1991. (1991 Form 10-K, Exhibit 10-8)

10-11	Basic Operating Agreement between the CAPCO Companies as amended January 1, 1993. (1993 Form 10-K, Exhibit 10-11)

10-12	Memorandum of Agreement effective as of September 1, 1980 among the CAPCO Group. (1982 Form 10-K, Exhibit 19-2)

10-13	Operating Agreement for Beaver Valley Power Station Units Nos. 1 and 2 as Amended and Restated September 15, 1987, by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 10-15)

10-14	Construction Agreement with respect to Perry Plant between the CAPCO Group dated as of July 22, 1974. (Registration No. 2-52251 of Toledo Edison Company, Exhibit 5(yy))

10-15	Amendment No. 3 dated as of October 31, 1980 to the Bond Guaranty dated as of October 1, 1973, as amended, with respect to the CAPCO Group. (Registration No. 2-68906 of Pennsylvania Power Company, Exhibit 10-16)

10-16	Amendment No. 4 dated as of July 1, 1985 to the Bond Guaranty dated as October 1, 1973, as amended, by the CAPCO Companies to National City Bank as Bond Trustee. (1985 Form 10-K, Exhibit 10-30)

10-17	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)

10-18	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)

10-19	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)

10-20	Bond Guaranty dated as of December 1, 1991, 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 10-35)

10-21	Memorandum of Understanding dated March 31, 1985 among the CAPCO Companies. (1985 Form 10-K, Exhibit 10-35)

(C)10-22	Ohio Edison System Executive Supplemental Life Insurance Plan. (1995 Form 10-K, Exhibit 10-44)

(C)10-23	Ohio Edison System Executive Incentive Compensation Plan. (1995 Form 10-K, Exhibit 10-45.)

(C)10-24	Ohio Edison System Restated and Amended Executive Deferred Compensation Plan. (1995 Form 10-K, Exhibit 10-46.)

(C)10-25	Ohio Edison System Restated and Amended Supplemental Executive Retirement Plan. (1995 Form 10-K, Exhibit 10-47.)

(C)10-28	Severance pay agreement between Ohio Edison Company and A. J. Alexander. (1995 Form 10-K, Exhibit 10-50.)

(D)10-30	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.)

(D)10-31	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.)

(D)10-32	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.)

(D)10-33	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.)

(D)10-34	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.)

(D)10-35	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.)

(D)10-36	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.)

(D)10-37	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.)

(D)10-38	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.)

(D)10-39	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.)

(D)10-40	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.)


(D)10-41	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.)

(D)10-42	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.)

(D)10-43	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.)

(D)10-44	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.)

(D)10-45	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.)

(D)10-46	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.)

(D)10-47	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.)

(D)10-48	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.)

(D)10-49	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.)

(D)10-50	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.)

(D)10-51	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.)

(D)10-52	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.)

(D)10-53	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.)

(D)10-54	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.)