Repurchase and Remarketing of Auction Rate Bonds

Between February 27, 2008 and April 2, 2008, FirstEnergy’s subsidiaries repurchased all of their tax-exempt long-term PCRBs originally sold at auction rates ($530 million) in response to disruptions in the auction rate securities market. In February 2008, FGCO, NGC, Met-Ed and Penelec elected to convert all of their then outstanding auction rate PCRBs to a weekly rate mode, which required their mandatory purchase of these PCRBs on the applicable conversion dates. The companies initially funded the repurchase with short-term debt. On April 22, 2008, Met-Ed ($28.5 million) and Penelec ($45 million) successfully marketed their converted PCRBs in a variable-rate mode. Subject to market conditions, FGCO and NGC plan to remarket their converted PCRBs later in 2008, either in fixed-rate or variable-rate modes.

Three Months Ended

FirstEnergy

FES

CEI

TE

JCP&L

Met-Ed

Penelec

(In millions)

Balance as of July 1, 2007

$
5,898

$
24

$
1,689

$
501

$
1,962

$
496

$
861

Adjustments related to GPU acquisition

(289
)
-
-

-

(136
)

(70
)

(83
)
Balance as of September 30, 2007

$
5,609

$
24

$
1,689

$
501

$
1,826

$
426

$
778

Non-Core Asset Sale

Nine Months Ended

FirstEnergy

FES

CEI

TE

JCP&L

Met-Ed

Penelec

(In millions)

Balance as of January 1, 2007

$
5,898

$
24

$
1,689

$
501

$
1,962

$
496

$
861

Adjustments related to GPU acquisition

(289
)
-
-

-

(136
)

(70
)

(83
)
Balance as of September 30, 2007

$
5,609

$
24

$
1,689

$
501

$
1,826

$
426

$
778

~~4. DIVESTITURES AND DISCONTINUED OPERATIONS~~

~~In 2006,~~On March 7, 2008, FirstEnergy sold ~~its remaining FSG subsidiaries (Roth Bros., Hattenbach, Dunbar, Edwards and RPC)~~substantially all of the assets of FirstEnergy Telecom Services, Inc. to FirstCom for ~~an aggregate net after-tax gain of $2.2 million. Hattenbach, Dunbar, Edwards, and RPC are included~~$45 million in ~~discontinued operations for the third quarter and nine months ended September 30, 2006; Roth Bros. did not meet the criteria for that classification.~~

~~In March 2006, FirstEnergy sold 60% of its interest~~cash, with FirstCom also assuming related liabilities. The sale resulted in ~~MYR for~~ an after-tax gain of ~~$0.2 million. In June 2006, as part of the March agreement,~~approximately $0.06 per share. FirstEnergy ~~sold an additional 1.67% interest. As~~is a ~~result of the March sale, FirstEnergy deconsolidated MYR~~15.6% shareholder 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.FirstCom.

The income for the period that MYR was accounted for as an equity method investment has not been included in discontinued operations; however, results prior to the initial sale in March 2006, including the gain on the sale, are reported as discontinued operations.

Revenues associated with discontinued operations were $36 million and $211 million in the third quarter and first nine months of 2006, respectively. The following table summarizes the net income (loss) included in "Discontinued Operations" on the Consolidated Statements of Income for the three months and nine months ended September 30, 2006:

Three Months

Nine Months

(In millions)

FSG subsidiaries $ 2 $ (6 )
MYR - 2
Total $ 2 $ (4 )

~~5. DERIVATIVE INSTRUMENTS~~FIRSTENERGY’S BUSINESS

FirstEnergy is ~~exposed to financial risks resulting from the fluctuation~~a diversified energy company headquartered in Akron, Ohio, that operates primarily through three core business segments (see Results of interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight for risk management activities throughout FirstEnergy. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.Operations).

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 using traditional accrual accounting. The changes in the fair value of derivative instruments that do not meet the normal purchase and normal sales criterion are recorded as other expense, as AOCL, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness.

Energy Delivery Services transmits and distributes electricity through FirstEnergy’s eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR and default service requirements in Pennsylvania and New Jersey. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy’s service areas at regulated rates, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service) in its Pennsylvania and New Jersey franchise areas. The segment’s net income reflects the commodity costs of securing electricity from FirstEnergy’s competitive energy services segment under partial requirements purchased power agreements with FES and from non-affiliated power suppliers, including, in each case, associated transmission costs.

FirstEnergy hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases and anticipated interest payments associated with future debt issues. The effective portion of such hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings.

Competitive Energy Services supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the PLR and default service requirements of FirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns or leases and operates 19 generating facilities with a net demonstrated capacity of approximately 13,664 MW and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated company power sales and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.

Ohio Transitional Generation Services supplies the electric power needs of non-shopping customers under the default service requirements of the Ohio Companies. The segment's net income is primarily derived from electric generation sales revenues less the cost of power purchased from the competitive energy services segment through a full-requirements PSA arrangement with FES, including net transmission and ancillary costs charged by MISO to deliver energy to retail customers.

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 13 to the consolidated financial statements. Net income by major business segment was as follows:

	Three Months Ended
	March 31,								Increase
	2008				2007				(Decrease)
Net Income	(In millions, except per share data)
By Business Segment
Energy delivery services		$	179			$	218			$	(39	)
Competitive energy services			87				98				(11	)
Ohio transitional generation services			23				24				(1	)
Other and reconciling adjustments*			(13	)			(50	)			37
Total		$	276			$	290			$	(14	)

Basic Earnings Per Share		$	0.91			$	0.92			$	(0.01	)
Diluted Earnings Per Share		$	0.90			$	0.92			$	(0.02	)

* Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, telecommunications services and elimination of intersegment transactions.

Summary of Results of Operations – First Quarter 2008 Compared with First Quarter 2007

Financial results for FirstEnergy's major business segments in the first three months of 2008 and 2007 were as follows:

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Quarter 2008 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	2,050		$	289		$	691		$	-		$	3,030
Other		162			40			16			29			247
Internal		-			776			-			(776	)		-
Total Revenues		2,212			1,105			707			(747	)		3,277

Expenses:
Fuel and purchased power		983			533			588			(776	)		1,328
Other operating expenses		445			309			77			(31	)		800
Provision for depreciation		106			53			-			5			164
Amortization of regulatory assets		249			-			9			-			258
Deferral of new regulatory assets		(100	)		-			(5	)		-			(105	)
General taxes		173			32			1			9			215
Total Expenses		1,856			927			670			(793	)		2,660

Operating Income		356			178			37			46			617
Other Income (Expense):
Investment income		45			(6	)		1			(23	)		17
Interest expense		(103	)		(34	)		-			(42	)		(179	)
Capitalized interest		-			7			-			1			8
Total Other Income (Expense)		(58	)		(33	)		1			(64	)		(154	)

Income Before Income Taxes		298			145			38			(18	)		463
Income taxes		119			58			15			(5	)		187
Net Income	$	179		$	87		$	23		$	(13	)	$	276

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Quarter 2007 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	1,875		$	276		$	613		$	-		$	2,764
Other		165			45			6			(7	)		209
Internal		-			714			-			(714	)		-
Total Revenues		2,040			1,035			619			(721	)		2,973

Expenses:
Fuel and purchased power		844			447			544			(714	)		1,121
Other operating expenses		408			300			49			(8	)		749
Provision for depreciation		98			51			-			7			156
Amortization of regulatory assets		246			-			5			-			251
Deferral of new regulatory assets		(124	)		-			(20	)		-			(144	)
General taxes		165			28			2			8			203
Total Expenses		1,637			826			580			(707	)		2,336

Operating Income		403			209			39			(14	)		637
Other Income (Expense):
Investment income		70			3			1			(41	)		33
Interest expense		(109	)		(52	)		(1	)		(23	)		(185	)
Capitalized interest		2			3			-			-			5
Total Other income (Expense)		(37	)		(46	)		-			(64	)		(147	)

Income Before Income Taxes		366			163			39			(78	)		490
Income taxes		148			65			15			(28	)		200
Net Income	$	218		$	98		$	24		$	(50	)	$	290


Changes Between First Quarter 2008 and
First Quarter 2007 Financial Results
Increase (Decrease)

Revenues:
External
Electric	$	175		$	13		$	78		$	-		$	266
Other		(3	)		(5	)		10			36			38
Internal		-			62			-			(62	)		-
Total Revenues		172			70			88			(26	)		304

Expenses:
Fuel and purchased power		139			86			44			(62	)		207
Other operating expenses		37			9			28			(23	)		51
Provision for depreciation		8			2			-			(2	)		8
Amortization of regulatory assets		3			-			4			-			7
Deferral of new regulatory assets		24			-			15			-			39
General taxes		8			4			(1	)		1			12
Total Expenses		219			101			90			(86	)		324

Operating Income		(47	)		(31	)		(2	)		60			(20	)
Other Income (Expense):
Investment income		(25	)		(9	)		-			18			(16	)
Interest expense		6			18			1			(19	)		6
Capitalized interest		(2	)		4			-			1			3
Total Other Income (Expense)		(21	)		13			1			-			(7	)

Income Before Income Taxes		(68	)		(18	)		(1	)		60			(27	)
Income taxes		(29	)		(7	)		-			23			(13	)
Net Income	$	(39	)	$	(11	)	$	(1	)	$	37		$	(14	)

Energy Delivery Services – First Quarter 2008 Compared with First Quarter 2007

Net income decreased $39 million to $179 million in the first three months of 2008 compared to $218 million in the first three months of 2007, primarily due to higher operating expenses partially offset by increased revenues.

Revenues –

The increase in total revenues resulted from the following sources:

	Three Months Ended
	March 31,				Increase
Revenues by Type of Service	2008		2007		(Decrease)
	(In millions)
Distribution services	$	955	$	944	$	11
Generation sales:
Retail		790		720		70
Wholesale		219		132		87
Total generation sales		1,009		852		157
Transmission		197		183		14
Other		51		61		(10	)
Total Revenues	$	2,212	$	2,040	$	172

The change in distribution deliveries by customer class is summarized in the following table:

Electric Distribution KWH Deliveries
Residential	2.4	%
Commercial	1.9	%
Industrial	(1.0	)%
Total Distribution KWH Deliveries	1.2	%

The increase in electric distribution deliveries to customers was primarily due to increased weather-related usage in the Ohio Companies’ and Penn’s service territories during the first three months of 2008 compared to the same period of 2007 (heating degree days increased 2.4%). The higher revenues from increased distribution deliveries were partially offset by the residual effects of the distribution rate decreases for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).

The following table summarizes the price and volume factors contributing to the $157 million increase in generation revenues in the first quarter of 2008 compared to the first quarter of 2007:

Sources of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 0.7% decrease in sales volumes	$	(5	)
Change in prices		75
		70
Wholesale:
Effect of 8.9% increase in sales volumes		12
Change in prices		75
		87
Net Increase in Generation Revenues	$	157

The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in Penn’s and JCP&L’s service territories in the first three months of 2008. The increase in retail generation prices during the first three months of 2008 reflected increased generation rates for JCP&L resulting from the New Jersey BGS auction process and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market. The increase in prices reflected higher spot market prices for PJM market participants.

Transmission revenues increased $14 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred with no material effect on current period earnings (see Outlook – State Regulatory Matters – Pennsylvania).

Expenses –

The increases in revenues discussed above were offset by a $219 million increase in expenses due to the following:

Purchased power costs were $139 million higher in the first three months of 2008 due to higher unit costs and a decrease in the amount of NUG costs deferred. The increased unit costs reflected the effect of higher JCP&L costs resulting from the BGS auction process. 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. The following table summarizes the sources of changes in purchased power costs:

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	84
Change due to decreased volumes		(18	)
		66
Purchases from FES:
Change due to decreased unit costs		(4	)
Change due to increased volumes		17
		13

Decrease in NUG costs deferred		60
Net Increase in Purchased Power Costs	$	139

Other operating expenses increased $37 million due primarily to the effects of:

-	An increase of $15 million in MISO and PJM transmission expenses, resulting primarily from higher congestion costs (see transmission revenues discussion above).

-	An increase in operation and maintenance expenses of $11 million for storm restoration work during the first quarter of 2008.

-	An increase in labor expenses of $9 million primarily due to an increase in the number of employees in the first quarter of 2008 compared to 2007 as a result of the segment’s workforce initiatives.

An increase of $3 million in amortization of regulatory assets compared to 2007 due primarily to recovery of deferred BGS costs through higher NUGC rates for JCP&L.

The deferral of new regulatory assets during the first three months of 2008 was $24 million lower primarily due to the absence of the deferral in 2007 of decommissioning costs related to the Saxton nuclear research facility.

Depreciation expense increased $8 million due to property additions since the first quarter of 2007.

General taxes increased $8 million due to higher property taxes and gross receipts taxes.

Other Expense –

Other expense increased $21 million in 2008 compared to the first three months of 2007 primarily due to lower investment income of $25 million resulting from the repayment of notes receivable from affiliates since the first quarter of 2007, partially offset by lower interest expense (net of capitalized interest) of $4 million.

Competitive Energy Services – First Quarter 2008 Compared with First Quarter 2007

Net income for this segment was $87 million in the first three months of 2008 compared to $98 million in the same period in 2007. The $11 million reduction in net income reflects a decrease in gross generation margin and higher operating costs which were partially offset by lower interest expense.

Revenues –

Total revenues increased $70 million in the first three months of 2008 compared to the same period in 2007. This increase primarily resulted from higher unit prices on affiliated generation sales to the Ohio Companies and increased non-affiliated wholesale sales, which were partially offset by lower retail sales.

The increase in reported segment revenues resulted from the following sources:

	Three Months Ended
	March 31,				Increase
Revenues by Type of Service	2008		2007		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	160	$	174	$	(14	)
Wholesale		129		103		26
Total Non-Affiliated Generation Sales		289		277		12
Affiliated Generation Sales		776		714		62
Transmission		33		23		10
Other		7		21		(14	)
Total Revenues	$	1,105	$	1,035	$	70

The lower retail revenues resulted from decreased sales in the PJM market, partially offset by increased sales in the MISO market. The decrease in PJM retail sales is primarily the result of lower contract renewals for commercial and industrial customers. The increase in MISO retail sales is primarily the result of capturing more shopping customers in Penn’s service territory, partially offset by lower customer usage. Higher non-affiliated wholesale revenues resulted from the effect of increased generation available for the non-affiliated wholesale market.

The increased affiliated company generation revenues were due to increased sales volumes and higher unit prices for the Ohio Companies, partially offset by lower unit prices for the Pennsylvania Companies. The increase in PSA sales to the Ohio Companies was due to their higher retail generation sales requirements. The higher unit prices reflected increases in the Ohio Companies’ retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn due to a 45% increase in customer shopping in the first quarter of 2008 compared to the first quarter of 2007.

The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:

Source of Change in Non-Affiliated Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 9.0% decrease in sales volumes	$	(16	)
Change in prices		2
		(14	)
Wholesale:
Effect of 3.5% increase in sales volumes		4
Change in prices		22
		26
Net Increase in Non-Affiliated Generation Revenues	$	12

Source of Change in Affiliated Generation Revenues	Increase (Decrease)
	(In millions)
Ohio Companies:
Effect of 1.2% increase in sales volumes	$	6
Change in prices		44
		50
Pennsylvania Companies:
Effect of 9.0% increase in sales volumes		16
Change in prices		(4	)
		12
Net Increase in Affiliated Generation Revenues	$	62

Transmission revenues increased $10 million due to increased retail load in the MISO market and higher transmission rates ($12 million), partially offset by reduced financial transmission rights auction revenue ($2 million). Other revenue decreased $14 million primarily due to lower interest income from short-term investments.

Expenses -

Total expenses increased $101 million in the first three months of 2008 due to the following factors:

Fossil fuel costs increased $68 million due to increased generation volumes ($37 million) and higher unit prices ($31 million). The increased unit prices primarily reflect higher coal transportation costs ($24 million) and increased emission allowance costs ($5 million) in the first quarter of 2008.

Purchased power costs increased $20 million due primarily to higher market rates, partially offset by reduced volume requirements due to increased generation from internal resources.

Nuclear operating costs increased $23 million due to this year’s Davis-Besse refueling outage and the preparatory work associated with the Beaver Valley Unit 2 refueling outage scheduled for the second quarter of 2008.

Other expense increased $15 million due primarily to the assignment of CEI’s and TE’s leasehold interests in the Bruce Mansfield Plant to FGCO in the fourth quarter of 2007 ($7 million) and reduced earnings on life insurance investments during the first quarter of 2008 ($6 million).

Higher depreciation expenses of $2 million were due to property additions since the first quarter of 2007.

Higher general taxes of $4 million resulted from increased gross receipts taxes and property taxes.

Partially offsetting the higher costs were:

Fossil operating costs were $23 million lower due to fewer outages in 2008 compared to 2007 and increased gains on emission allowance sales.

Transmission expense declined $7 million due to reduced PJM congestion charges and a change in MISO revenue sufficiency guarantee settlements.

Other Expense –

Total other expense in the first three months of 2008 was $13 million lower than the first quarter of 2007, primarily due to a decline in interest expense (net of capitalized interest) of $22 million due to the repayment of notes payable to affiliates since the first quarter of 2007 and a $2 million increase in earnings from nuclear decommissioning trust investments, partially offset by an $11 million increase in trust securities impairments.

Ohio Transitional Generation Services – First Quarter 2008 Compared with First Quarter 2007

Net income for this segment decreased to $23 million in the first three months of 2008 from $24 million in the same period of 2007. Higher operating expenses, primarily for purchased power, were almost entirely offset by higher generation revenues.

Revenues –

The increase in reported segment revenues resulted from the following sources:

	Three Months Ended
	March 31,
Revenues by Type of Service	2008		2007		Increase
	(In millions)
Generation sales:
Retail	$	606	$	546	$	60
Wholesale		3		2		1
Total generation sales		609		548		61
Transmission		93		71		22
Other		5		-		5
Total Revenues	$	707	$	619	$	88

The ~~net deferred losses~~following table summarizes the price and volume factors contributing to the increase in sales revenues from retail customers:

Source of Change in Retail Generation Revenues	Increase
	(In millions)
Effect of 1.3% increase in sales volumes	$	7
Change in prices		53
Total Increase in Retail Generation Revenues	$	60

The increase in generation sales was primarily due to higher weather-related usage in the first three months of ~~$52 million included in AOCL as of September 30, 2007, for derivative hedging activity, as~~2008 compared to ~~$58~~the same period of 2007 and reduced customer shopping. Heating degree days in OE’s, CEI’s and TE’s service territories increased by 2.8%, 1.7% and 3.3%, respectively. Average prices increased primarily due to an increase in the Ohio Companies’ fuel cost recovery rider that became effective in January 2008. The percentage of generation services provided by alternative suppliers to total sales delivered by the Ohio Companies in their service areas decreased by 1.8 percentage points from the same period in 2007.

Increased transmission revenue resulted from higher sales volumes ($7 million) and a PUCO-approved transmission tariff increase ($15 million) that became effective July 1, 2007.

Expenses -

Purchased power costs were $44 million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	(5	)
Change due to decreased volumes		(1	)
		(6	)
Purchases from FES:
Change due to increased unit costs		44
Change due to increased volumes		6
		50
Net Increase in Purchased Power Costs	$	44

The increase in purchase volumes from FES was due to the higher retail generation sales requirements described above. The higher unit costs reflect the increases in the Ohio Companies’ retail generation rates, as provided for under the PSA with FES.

Other operating expenses increased $28 million due in part to MISO transmission-related expenses ($12 million). The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings. The remainder of the increase resulted from lower associated company cost reimbursements related to the Ohio Companies’ generation leasehold interests.

Other – First Quarter 2008 Compared with First Quarter 2007

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. In 2008 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

As of March 31, 2008, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to the initial short-term funding of the repurchase of certain auction rate bonds described below and the classification of certain variable interest rate PCRBs as currently payable long-term debt. The PCRBs currently permit individual debt holders to put the respective debt back to the issuer for purchase prior to maturity.

Changes in Cash Position

FirstEnergy's primary source of cash required for continuing operations as a holding company is cash from the operations of its subsidiaries. FirstEnergy and certain of its subsidiaries also have access to $2.75 billion of short-term financing under a revolving credit facility which expires in 2012. Under the terms of the facility, FirstEnergy is permitted to have up to $1.5 billion in outstanding borrowings at any time, subject to the facility cap of $2.75 billion of aggregate outstanding borrowings by it and its subsidiaries that are also parties to such facility. In the first three months of 2008, FirstEnergy received $88 million of cash dividends from its subsidiaries and paid $168 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by the subsidiaries of FirstEnergy.

As of March 31, 2008, FirstEnergy had $70 million of cash and cash equivalents compared with $129 million as of December 31, 2006, resulted from a net $10 million increase related to current hedging activity and a $16 million decrease due to net hedge losses reclassified to earnings during the nine months ended September 30, 2007. Based on current estimates, approximately $14 million (after tax) of the net deferred losses on derivative instruments in AOCL as of September 30, 2007 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The ~~fair value of these derivative instruments fluctuate from period to period based on various market factors.~~

~~FirstEnergy has entered into swaps that have been designated as fair value hedges of fixed-rate, long-term debt issues to protect against the risk~~major sources of changes in ~~the fair value~~these balances are summarized below.

Cash Flows From Operating Activities

FirstEnergy's consolidated net cash from operating activities is provided primarily by its energy delivery services and competitive energy services businesses (see Results of ~~fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. During~~Operations above). Net cash provided from operating activities was $356 million in the first ~~nine~~three months of 2008 compared to $57 million used for operating activities in the first three months of 2007, ~~FirstEnergy unwound swaps with a total notional value of $150 million, for which it incurred $8 million~~as summarized in ~~cash losses that will be recognized as interest expense over~~ the ~~remaining maturity of each hedged security. As of September 30, 2007, FirstEnergy had interest rate swaps with an aggregate notional value of $600 million and a fair value of $(14) million.~~

During 2006 and the first nine months of 2007, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated issuances of fixed-rate, long-term debt securities for one or more of its subsidiaries as outstanding debt matures during 2007 and 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. During the first nine months of 2007, FirstEnergy terminated swaps with a notional value of $1.6 billion for which it paid $20 million, all of which were deemed effective. FirstEnergy will recognize the $20 million loss over the life of the associated future debt. As of September 30, 2007, FirstEnergy had forward swaps with an aggregate notional amount of $400 million and a fair value of $5 million.

~~6. ASSET RETIREMENT OBLIGATIONS~~following table:

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

The ARO liability of $1.2 billion as of September 30, 2007 is primarily related to the nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of September 30, 2007, the fair value of the decommissioning trust assets was approximately $2.1 billion.

~~The following tables analyze changes to the ARO balances during the three months and nine months ended September 30, 2007 and 2006, respectively.~~

Three Months Ended

FirstEnergy

FES

OE

CEI

TE

JCP&L

Met-Ed

Penelec

(In millions)

ARO Reconciliation

Balance, July 1, 2007 $ 1,228 $ 784 $ 91 $ 2 $ 27 $ 87 $ 156 $ 79
Liabilities incurred - - - - - - - -
Liabilities settled - - - - - - - -
Accretion 19 13 1 - 1 1 2 2
Revisions in estimated
cashflows - - - - - - - -
Balance, September 30, 2007 $ 1,247 $ 797 $ 92 $ 2 $ 28 $ 88 $ 158 $ 81

Balance, July 1, 2006 $ 1,160 $ 743 $ 85 $ 2 $ 26 $ 82 $ 146 $ 74
Liabilities incurred - - - - - - - -
Liabilities settled - - - - - - - -
Accretion 19 13 2 - - 1 3 2
Revisions in estimated
cashflows - - - - - - - -
Balance, September 30, 2006 $ 1,179 $ 756 $ 87 $ 2 $ 26 $ 83 $ 149 $ 76

	Three Months Ended
	March 31,
Operating Cash Flows	2008			2007
	(In millions)
Net income	$	276		$	290
Non-cash charges		203			125
Pension trust contribution		-			(300	)
Working capital and other		(123	)		(172	)
	$	356		$	(57	)

Net cash provided from operating activities increased by $413 million in the first three months of 2008 compared to the first three months of 2007 primarily due to the absence of a $300 million pension trust contribution in 2007, a $78 million increase in non-cash charges and a $49 million increase from working capital and other changes, partially offset by a $14 million decrease in net income (see Results of Operations above). The increase in non-cash charges is primarily due to lower deferrals of new regulatory assets and deferred purchased power costs. The deferral of new regulatory assets decreased primarily as a result of the absence of the deferral of decommissioning costs related to the Saxton nuclear research facility in the first quarter of 2007. Deferred purchased power costs decreased as a result of lower deferred NUG costs. The changes in working capital and other primarily resulted from a $149 million change in the collection of receivables and an $85 million change in the settlement of accounts payable, partially offset by increased tax payments compared to the first three months of 2007.

Cash Flows From Financing Activities

In the first three months of 2008, cash provided from financing activities was $227 million compared to $346 million in the first three months of 2007. The decrease was primarily due to lower short-term borrowings and debt issuances in the first quarter of 2008, partially offset by redemption of common stock in the first quarter of 2007. The following table summarizes security issuances and redemptions.

411

Nine Months Ended
  FirstEnergy

  FES

  OE

  CEI

  TE

  JCP&L

  Met-Ed
  Penelec

                          (In millions)

ARO Reconciliation

Balance, January 1, 2007 $ 1,190 $ 760 $ 88 $ 2 $ 27 $ 84 $ 151 $ 77
Liabilities incurred - - - - - - - -
Liabilities settled (2 ) (1 ) - - - - - -
Accretion 59 38 4 - 1 4 7 4
Revisions in estimated
cashflows - - - - - - - -
Balance, September 30, 2007 $ 1,247 $ 797 $ 92 $ 2 $ 28 $ 88 $ 158 $ 81

Balance, January 1, 2006 $ 1,126 $ 716 $ 83 $ 8 $ 25 $ 80 $ 142 $ 72
Liabilities incurred - - - - - - - -
Liabilities settled (6 ) - - (6 ) - - - -
Accretion 55 36 4 - 1 3 7 4
Revisions in estimated
cashflows 4 4 - - - - - -
Balance, September 30, 2006 $ 1,179 $ 756 $ 87 $ 2 $ 26 $ 83 $ 149 $ 76

~~7. PENSION AND OTHER POSTRETIREMENT BENEFITS~~

	Three Months Ended
	March 31,
Securities Issued or Redeemed	2008		2007
	(In millions)
New issues
Unsecured notes	$	-	$	250

Redemptions
Pollution control notes(1)	$	362	$	-
Senior secured notes		6		13
Common stock		-		891
	$	368	$	904

Short-term borrowings, net	$	746	$	1,139

(1) Includes the repurchase of certain auction rate PCRBs described below, which were extinguished from FirstEnergy’s consolidated balance sheet.

FirstEnergy ~~provides noncontributory defined benefit pension plans that cover substantially all~~had approximately $1.6 billion of ~~its and its subsidiaries’ employees. The trusteed plans provide defined benefits based on years~~short-term indebtedness as of ~~service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December~~March 31, ~~measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value~~2008 compared to approximately $903 million as of December 31, 2006. On January 2, 2007, FirstEnergy made a $300 million voluntary cash contribution to its qualified pension plan. Projections indicate that additional cash contributions are not expected to be required before 2016. FirstEnergy also provides a minimum amount2007. Available bank borrowing capability as of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. During 2006, FirstEnergy amended the health care plan effective inMarch 31, 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized health care coverage. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

The components of FirstEnergy's net periodic pension and other postretirement benefit costs (including amounts capitalized) for the three months and nine months ended September 30, 2007 and 2006 consisted ofincluded the following:

Three Months Ended
Nine Months Ended

September 30,

September 30,

Pension Benefits

2007

2006

2007

2006

(In millions)

Service cost $ 21 $ 21 $ 63 $ 63
Interest cost 71 66 213 199
Expected return on plan assets (112 ) (99 ) (337 ) (297 )
Amortization of prior service cost 2 2 7 7
Recognized net actuarial loss 10 15 31 44
Net periodic cost (credit) $ (8 ) $ 5 $ (23 ) $ 16

Borrowing Capability (In millions)
Short-term credit facilities(1)	$	2,870
Accounts receivable financing facilities		550
Utilized		(1,646	)
LOCs		(60	)
Net available capability	$	1,714

(1) Includes the $2.75 billion revolving credit facility described below, a $100 million revolving credit facility that expires in December 2009 and a $20 million uncommitted line of credit.

Three Months Ended
Nine Months Ended

September 30,

September 30,

Other Postretirement Benefits

2007

2006

2007

2006

(In millions)

Service cost $ 5 $ 9 $ 16 $ 26
Interest cost 17 26 52 79
Expected return on plan assets (12 ) (12 ) (38 ) (35 )
Amortization of prior service cost (37 ) (19 ) (112 ) (57 )
Recognized net actuarial loss 11 14 34 42
Net periodic cost (credit) $ (16 ) $ 18 $ (48 ) $ 55
As of March 31, 2008, the Ohio Companies and Penn had the aggregate capability to issue approximately $3.4 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $573 million, $449 million and $121 million, respectively, as of March 31, 2008.

The applicable earnings coverage tests in the respective charters of OE, TE, Penn and JCP&L are currently inoperative. In the event that any of them issues preferred stock in the future, the applicable earnings coverage test will govern the amount of preferred stock that may be issued. CEI, Met-Ed and Penelec do not have similar restrictions and could issue up to the number of preferred shares authorized under their respective charters.

As of March 31, 2008, FirstEnergy had approximately $1.0 billion of remaining unused capacity under an existing shelf registration statement filed with the SEC in 2003 to support future securities issuances. The shelf registration expires in December 2008 and provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units. As of March 31, 2008, OE had approximately $400 million of remaining unused capacity under a shelf registration for unsecured debt securities filed with the SEC in 2006 that expires in April 2009.

FirstEnergy and certain of its subsidiaries are party to a $2.75 billion five-year revolving credit facility (included in the borrowing capability table above). FirstEnergy has the capability to request an increase in the total commitments available under this facility up to a maximum of $3.25 billion. Commitments under the facility are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.

512

~~Pension~~The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations:

	Revolving			Regulatory and
	Credit Facility			Other Short-Term
Borrower	Sub-Limit			Debt Limitations(1)
	(In millions)
FirstEnergy	$	2,750		$	-	(2)
OE		500			500
Penn		50			39	(3)
CEI		250	(4)		500
TE		250	(4)		500
JCP&L		425			428	(3)
Met-Ed		250			300	(3)
Penelec		250			300	(3)
FES		1,000			-	(2)
ATSI		-	(5)		50

(1)As of March 31, 2008. (2)No regulatory approvals, statutory or charter limitations applicable. (3)Excluding amounts which may be borrowed under the regulated companies’ money pool. (4)Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s. (5)The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) ATSI has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed ATSI’s obligations of such borrower under the facility.

The revolving credit facility, combined with an aggregate $550 million (unused as of March 31, 2008) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet working capital requirements and for other ~~postretirement benefit obligations are allocated~~general corporate purposes for FirstEnergy and its subsidiaries.

Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.

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 March 31, 2008, FirstEnergy’s ~~subsidiaries employing~~and its subsidiaries' debt to total capitalization ratios (as defined under the plan participants. FirstEnergy’s subsidiaries capitalize employee benefit costs related to construction projects. The net periodic pension and other postretirement benefit costs (including amounts capitalized) recognized by FES and each of the Companies for the three months and nine months ended September 30, 2007 and 2006revolving credit facility) were as follows:

Three Months Ended

Nine Months Ended

September 30,

September 30,

Pension Benefit Cost (Credit)

2007

2006

2007

2006

(In millions)

FES $ 5.2 $ 9.9 $ 15.7 $ 29.9
OE (4.0 ) (1.5 ) (11.9 ) (4.5 )
CEI 0.3 1.0 0.9 2.9
TE - 0.2 (0.1 ) 0.7
JCP&L (2.1 ) (1.4 ) (6.4 ) (4.1 )
Met-Ed (1.7 ) (1.7 ) (5.1 ) (5.2 )
Penelec (2.6 ) (1.3 ) (7.7 ) (4.0 )
Other FirstEnergy subsidiaries (2.7 ) - (8.1 ) -
$ (7.6 ) $ 5.2 $ (22.7 ) $ 15.7

Borrower
FirstEnergy	58	%
OE	43	%
Penn	25	%
CEI	57	%
TE	42	%
JCP&L	30	%
Met-Ed	47	%
Penelec	49	%
FES	61	%

Three Months Ended

Nine Months Ended

September 30,

September 30,

Other Postretirement Benefit Cost (Credit)

2007

2006

2007

2006

(In millions)

FES $ (2.4 ) $ 3.4 $ (7.4 ) $ 10.2
OE (2.7 ) 4.2 (8.0 ) 12.6
CEI 1.0 2.8 2.9 8.3
TE 1.2 2.0 3.7 6.1
JCP&L (4.0 ) 0.6 (11.9 ) 1.8
Met-Ed (2.5 ) 0.7 (7.7 ) 2.2
Penelec (3.2 ) 1.8 (9.5 ) 5.4
Other FirstEnergy subsidiaries (3.3 ) 2.7 (9.8 ) 7.9
$ (15.9 ) $ 18.2 $ (47.7 ) $ 54.5
The revolving credit facility does not contain provisions that either restrict the 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 the credit ratings of the company borrowing the funds.

~~8. VARIABLE INTEREST ENTITIES~~

~~FIN 46R addresses~~FirstEnergy's regulated companies also have the ~~consolidation~~ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of ~~VIEs, including special-purpose entities, that~~FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first three months of 2008 was 3.62% for the regulated companies’ money pool and 3.55% for the unregulated companies�� money pool.

FirstEnergy’s access to capital markets and costs of financing are ~~not controlled through voting interests or in which~~influenced by the ~~equity investors do not bear~~ratings of its securities. The following table displays FirstEnergy’s, FES’ and the ~~entity's residual economic risks and rewards.~~Companies’ securities ratings as of March 31, 2008. S&P’s outlook of FirstEnergy and its subsidiaries ~~consolidate VIEs when they are determined to be the VIE's primary beneficiary as defined by FIN 46R.~~remains negative and Moody’s outlook for FirstEnergy and its subsidiaries remains stable.

Issuer	Securities	S&P	Moody’s

FirstEnergy	Senior unsecured	BBB-	Baa3

FES	Senior unsecured	BBB	Baa2

OE	Senior unsecured	BBB-	Baa2

CEI	Senior secured	BBB+	Baa2
	Senior unsecured	BBB-	Baa3

TE	Senior unsecured	BBB-	Baa3

Penn	Senior secured	A-	Baa1

JCP&L	Senior unsecured	BBB	Baa2

Met-Ed	Senior unsecured	BBB	Baa2

Penelec	Senior unsecured	BBB	Baa2

~~Trusts~~Cash Flows From Investing Activities

~~FirstEnergy’s consolidated financial statements~~Net cash flows used in investing activities resulted principally from property additions. Energy delivery services property additions primarily include ~~PNBV~~expenditures related to transmission and ~~Shippingport, VIEs created in 1996~~distribution facilities. Capital spending by the competitive energy services segment are principally generation-related. The following table summarizes investing activities for the three months ended March 31, 2008 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.2007 by business segment:

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-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 $827 million, $758 million and $758 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 $606 million, $73 million and $429 million, respectively, that would not be payable if the casualty value payments are made.

Summary of Cash Flows	Property
Provided from (Used for) Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Three Months Ended March 31, 2008
Energy delivery services	$	(255	)	$	33		$	2		$	(220	)
Competitive energy services		(462	)		(3	)		(19	)		(484	)
Other		(12	)		68			-			56
Inter-Segment reconciling items		18			(12	)		-			6
Total	$	(711	)	$	86		$	(17	)	$	(642	)

Three Months Ended March 31, 2007
Energy delivery services	$	(155	)	$	44		$	10		$	(101	)
Competitive energy services		(124	)		(9	)		(4	)		(137	)
Other		(1	)		(16	)		(4	)		(21	)
Inter-Segment reconciling items		(16	)		(15	)		-			(31	)
Total	$	(296	)	$	4		$	2		$	(290	)

614

~~Effective October 16, 2007, CEI and TE assigned their leasehold interests~~Net cash used for investing activities in the ~~Bruce Mansfield Plant to FGCO. FGCO assumed all~~first quarter of ~~CEI’s and TE’s obligations arising under those leases. However, CEI and TE will remain primarily liable on the leases and related agreements as~~2008 increased by $352 million compared to the ~~lessors~~first quarter of 2007. The increase was principally due to a $415 million increase in property additions, which reflects AQC system expenditures and ~~other parties to~~ the ~~agreements. The assignment terminates automatically upon~~acquisition of a partially completed natural gas fired generating plant in Fremont, Ohio. Partially offsetting the ~~termination~~increase in property additions were cash proceeds from the sale of ~~the underlying leases.~~telecommunication assets.

~~Power Purchase Agreements~~

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

FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests inDuring the remaining ~~eight entities, which sell their output at variable prices that correlate to some extent with the operating costs~~three quarters of ~~the plants. As required by FIN 46R, FirstEnergy periodically requests from these eight entities the information necessary to determine whether they~~2008, capital requirements for property additions and capital leases 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 September 30, 2007, the net above-market loss liability projected for these eight NUG agreements was $158 million. Purchased power costs from these entities during the three months and nine months ended September 30, 2007 and 2006 are shown in the following table:

Three Months Ended

Nine Months Ended

September 30,

September 30,

2007

2006

2007

2006

(In millions)

JCP&L $ 30 $ 29 $ 71 $ 63
Met-Ed 13 12 40 45
Penelec 7 8 22 22
Total $ 50 $ 49 $ 133 $ 130

~~Transition Bonds~~

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

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of September 30, 2007, $404 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.

Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate quarterly servicing fees of $157,000 payable from TBC collections.

~~9. INCOME TAXES~~

On January 1, 2007, FirstEnergy adopted FIN 48, which provides guidance for accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. This interpretation prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. FIN 48 also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation is a two-step process. The first step is to determine if it is more likely than not that a tax position will be sustained upon examination, based on the merits of the position, and should therefore be recognized. The second step is to measure a tax position that meets the more likely than not recognition threshold to determine the amount of income tax benefit to recognize in the financial statements.

~~As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits was $268 million.~~approximately $1.4 billion. FirstEnergy recorded a $2.7 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate upon recognition. The majority of items that would not have affected the effective tax rate would be purchase accounting adjustments to goodwill upon recognition. During the first nine months of 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of September 30, 2007, the entire liability for uncertain tax positions is included in other non-current liabilities and changes to FirstEnergy’s tax contingencies that are reasonably possible in the next twelve months are not material.

FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the ~~amount previously taken or~~Companies have additional requirements of approximately $328 million for maturing long-term debt during the remainder of 2008. These cash requirements are expected to be ~~taken on the tax return. FirstEnergy includes net interest~~satisfied from a combination of internal cash, short-term credit arrangements and ~~penalties~~funds raised in the ~~provision~~capital markets.

FirstEnergy's capital spending for ~~income taxes, consistent with its policy prior~~the period 2008-2012 is expected to ~~implementing FIN 48. As~~be approximately $7.6 billion (excluding nuclear fuel), of ~~January 1, 2007,~~which approximately $2.0 billion applies to 2008. Investments for additional nuclear fuel during the ~~net amount~~2008-2012 period are estimated to be approximately $1.4 billion, of ~~interest accrued was $34 million.~~which about $150 million applies to 2008. During the ~~first nine months of 2007, there were no material changes~~same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $949 million and $111 million, respectively, as the ~~amount of interest accrued.~~nuclear fuel is consumed.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2006. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audit for years 2004 and 2005 began in June 2006 and is not expected to close before December 2007. The IRS began auditing the year 2006 in April 2006 under its Compliance Assurance Process experimental program, which is not expected to close before December 2007. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity (see Note 12). This transaction generated tax capital gains of approximately $752 million, all of which were offset by existing tax capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowances in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 3).

~~10. COMMITMENTS, GUARANTEES AND CONTINGENCIES~~

~~(A)~~ GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon FirstEnergy’s credit ratings.

As of ~~September 30, 2007,~~March 31, 2008, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances ~~aggregated approximately $4.7~~approximated $4.4 billion, ~~consisting of parental guarantees - $1.2 billion, subsidiaries’ guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $0.7 billion.~~as summarized below:

	Maximum
Guarantees and Other Assurances	Exposure
	(In millions)
FirstEnergy Guarantees of Subsidiaries
Energy and Energy-Related Contracts (1)	$	441
LOC (long-term debt) – interest coverage (2)		6
Other (3)		503
		950

Subsidiaries’ Guarantees
Energy and Energy-Related Contracts		86
LOC (long-term debt) – interest coverage (2)		6
Other (4)		2,641
		2,733

Surety Bonds		66
LOC (long-term debt) – interest coverage (2)		5
LOC (non-debt) (5)(6)		679
		750
Total Guarantees and Other Assurances	$	4,433

(1)

Issued for open-ended terms, with a 10-day termination right by FirstEnergy.

(2)

Reflects the interest coverage portion of LOCs issued in support of floating-rate

pollution control revenue bonds with various maturities. The principal amount of

floating-rate pollution control revenue bonds of $1.6 billion is reflected in debt on

FirstEnergy’s consolidated balance sheets.

(3)

Includes guarantees of $300 million for OVEC obligations and $80 million for nuclear

decommissioning funding assurances.

(4)

Includes FES’ guarantee of FGCO’s obligations under the sale and leaseback of Bruce

Mansfield Unit 1.

(5)

Includes $60 million issued for various terms pursuant to LOC capacity available under

FirstEnergy’s revolving credit facility.

(6)

Includes approximately $194 million pledged in connection with the sale and leaseback

of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in connection with the sale a

nd leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with

the sale and leaseback of Perry Unit 1 by OE.

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~~the financing or ~~refinancings~~refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or ~~financing~~financings 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~~FirstEnergy’s guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees ~~of $0.6 billion (included in the $1.2 billion discussed above) as of September 30, 2007 would~~will increase amounts otherwise ~~payable~~paid 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~~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 ~~September 30, 2007, FirstEnergy's~~March 31, 2008, FirstEnergy’s maximum exposure under these collateral provisions was ~~$442~~$440 million.

Most of ~~FirstEnergy's~~FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related ~~FirstEnergy~~ guarantees ~~of $75 million~~ provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction ~~jobs,~~contracts, environmental commitments and various retail transactions.

The Companies, with the exception of TE and JCP&L, each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company.

Borrowing

Subsidiary Company

Parent Company

Capacity

(In millions)

OES Capital, Incorporated OE $ 170
Centerior Funding Corp. CEI 200
Penn Power Funding LLC Penn 25
Met-Ed Funding LLC Met-Ed 80
Penelec Funding LLC Penelec 75
$ 550

FirstEnergy has ~~also~~ guaranteed the obligations of the operators of the TEBSA project up to a maximum of $6$2 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 ($2719 million as of ~~September 30, 2007)~~March 31, 2008), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

OFF-BALANCE SHEET ARRANGEMENTS

FES and the Ohio Companies have obligations that are not included on FirstEnergy’s Consolidated Balance Sheets related to sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. As of March 31, 2008, the present value of these sale and leaseback operating lease commitments, net of trust investments, totaled $2.4 billion.

FirstEnergy has equity ownership interests in certain businesses that are accounted for using the equity method of accounting for investments. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations are disclosed under “Guarantees and Other Assurances” above.

MARKET RISK INFORMATION

FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.

Commodity Price Risk

FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. 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 ~~LOC~~derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 2008 is summarized in the following table:

Increase (Decrease) in the Fair Value
of Commodity Derivative Contracts	Non-Hedge			Hedge			Total
	(In millions)
Change in the Fair Value of
Commodity Derivative Contracts:
Outstanding net liability as of January 1, 2008	$	(713	)	$	(26	)	$	(739	)
Additions/change in value of existing contracts		-			(11	)		(11	)
Settled contracts		58			17			75
Outstanding net liability as of March 31, 2008 (1)	$	(655	)	$	(20	)	$	(675	)

Non-commodity Net Liabilities as of March 31, 2008:
Interest rate swaps (2)		-			(3	)		(3	)
Net Liabilities - Derivative Contracts as of March 31, 2008	$	(655	)	$	(23	)	$	(678	)

Impact of Changes in Commodity Derivative Contracts(3)
Income Statement effects (pre-tax)	$	-		$	-		$	-
Balance Sheet effects:
Other comprehensive income (pre-tax)	$	-		$	6		$	6
Regulatory assets (net)	$	(58	)	$	-		$	(58	)

(1)

Includes $655 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.

(2)	Interest rate swaps are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements below).

(3)	Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

Derivatives are included on the Consolidated Balance Sheet as of March 31, 2008 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	-		$	62		$	62
Other liabilities		-			(77	)		(77	)

Non-Current-
Other deferred charges		28			12			40
Other non-current liabilities		(683	)		(20	)		(703	)

Net liabilities	$	(655	)	$	(23	)	$	(678	)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 4). Sources of information for the valuation of commodity derivative contracts as of March 31, 2008 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2008(1)			2009			2010			2011			2012			Thereafter			Total
	(In millions)
Prices actively quoted(2)	$	3		$	1		$	-		$	-		$	-		$	-		$	4
Other external sources(3)		(164	)		(192	)		(149	)		(92	)		-			-			(597	)
Prices based on models		-			-			-			-			(30	)		(52	)		(82	)
Total(4)	$	(161	)	$	(191	)	$	(149	)	$	(92	)	$	(30	)	$	(52	)	$	(675	)

(1) For the last three quarters of 2008.

(2) Represents exchange traded NYMEX futures and options.

(3) Primarily represents contracts based on broker and ICE quotes.

(4)

Includes $655 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of March 31, 2008. Based on derivative contracts held as of March 31, 2008, an adverse 10% change in commodity prices would decrease net income by approximately $3 million during the next 12 months.

Interest Rate Swap Agreements - Fair Value Hedges

FirstEnergy utilizes fixed-for-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk associated with its debt portfolio. 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, call options, fixed interest rates and interest payment dates match those of the underlying obligations. As of March 31, 2008, the debt underlying the $250 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 4.87%, which the swaps have converted to a current weighted average variable rate of 3.49%.

	March 31, 2008						December 31, 2007
	Notional		Maturity		Fair		Notional		Maturity		Fair
Interest Rate Swaps	Amount		Date		Value		Amount		Date		Value
	(In millions)
Fair value hedges	$	100		2008	$	1	$	100		2008	$	-
		150		2015		4		150		2015		(3	)
	$	250			$	5	$	250			$	(3	)

Forward Starting Swap Agreements - Cash Flow Hedges

FirstEnergy utilizes forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 2008 and 2009, and anticipated variable-rate, short-term debt. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury and LIBOR rates between the date of hedge inception and the date of the debt issuance. During the first three months of 2008, FirstEnergy entered into forward swaps with an aggregate notional value of $500 million and terminated forward swaps with an aggregate notional value of $300 million. FirstEnergy paid $18 million in cash related to the terminations, $1 million of which was ~~reduced~~deemed ineffective and recognized in current period earnings. The remaining effective portion ($17 million) will be recognized over the terms of the associated future debt. As of March 31, 2008, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $600 million and an aggregate fair value of $(8) million.

	March 31, 2008							December 31, 2007
	Notional		Maturity		Fair			Notional		Maturity		Fair
Forward Starting Swaps	Amount		Date		Value			Amount		Date		Value
	(In millions)
Cash flow hedges	$	100		2009	$	(2	)	$	-		2009	$	-
		100		2010		(1	)		-		2010		-
		25		2015		(2	)		25		2015		(1	)
		325		2018		-			325		2018		(1	)
		50		2020		(3	)		50		2020		(1	)
	$	600			$	(8	)	$	400			$	(3	)

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their fair value (market value) of approximately $1.2 billion and $1.4 billion, as of March 31, 2008 and December 31, 2007, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $120 million reduction in fair value as of March 31, 2008.

CREDIT RISK

Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB+ (S&P). As of March 31, 2008, the largest credit concentration was with one party, currently rated investment grade that represented 11% of FirstEnergy’s total approved credit risk. Within FirstEnergy’s unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserve, were with investment grade counterparties as of March 31, 2008.

OUTLOOK

State Regulatory Matters

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

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

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

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

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

·	continuing regulation of the Companies' transmission and distribution systems; and

·	requiring corporate separation of regulated and unregulated business activities.

The Companies and ATSI recognize, as regulatory assets, costs which the FERC, the PUCO, the PPUC and the NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $137 million as of March 31, 2008 (JCP&L - $78 million and Met-Ed - $59 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed. The following table discloses regulatory assets by company:

	March 31,		December 31,		Increase
Regulatory Assets*	2008		2007		(Decrease)
	(In millions)
OE	$	710	$	737	$	(27	)
CEI		854		871		(17	)
TE		188		204		(16	)
JCP&L		1,476		1,596		(120	)
Met-Ed		530		495		35
ATSI		39		42		(3	)
Total	$	3,797	$	3,945	$	(148	)

*	Penelec had net regulatory liabilities of approximately $67 million and $74 million as of March 31, 2008 and December 31, 2007, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

Regulatory assets by source are as follows:

	March 31,			December 31,			Increase
Regulatory Assets By Source	2008			2007			(Decrease)
	(In millions)
Regulatory transition costs	$	2,156		$	2,363		$	(207	)
Customer shopping incentives		495			516			(21	)
Customer receivables for future income taxes		290			295			(5	)
Loss on reacquired debt		56			57			(1	)
Employee postretirement benefits		37			39			(2	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(95	)		(115	)		20
Asset removal costs		(195	)		(183	)		(12	)
MISO/PJM transmission costs		368			340			28
Fuel costs - RCP		227			220			7
Distribution costs - RCP		361			321			40
Other		97			92			5
Total	$	3,797		$	3,945		$	(148	)

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. The proposed enhancements were divided into two groups: enhancements that were to be completed in 2004; and enhancements that were to be completed after 2004. In 2004, FirstEnergy completed all of the enhancements that were recommended for completion in 2004. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU performed a review of JCP&L’s service reliability. On June 9, 2004, the NJBPU approved a stipulation that addresses a third-party consultant’s recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation incorporates the consultant’s focused audit of, and recommendations regarding, JCP&L’s Planning and Operations and Maintenance programs and practices. On June 1, 2005, the consultant completed his work and issued his final report to the NJBPU. On July 14, 2006, JCP&L filed a comprehensive response to the consultant’s report with the NJBPU. JCP&L will complete the remaining substantive work described in the stipulation in 2008. JCP&L continues to file compliance reports with the NJBPU reflecting JCP&L’s activities associated with implementing the stipulation.

In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Companies and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including the ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.

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

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

Ohio

On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007, the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008, the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider, with alternative options for the recovery period ranging from five to twenty-five years. This second application is currently pending before the PUCO and a hearing has been set for July 15, 2008.

The Ohio Companies filed an application and rate request for an increase in electric distribution rates with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the average electric bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operation and maintenance expenses and recovery of regulatory assets that were authorized in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of their investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. This amount excludes the recovery of deferred fuel costs, whose recovery is now being sought in a separate proceeding before the PUCO, discussed above. On January 3, 2008, the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings, the PUCO Staff submitted testimony decreasing their recommended revenue increase to a range of $114 million to $132 million. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $45 million of interest costs deferred through March 31, 2008 ($0.09 per share of common stock). The PUCO is expected to render its decision during the second or third quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing retail generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per KWH would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. A slice-of-system approach would require the successful bidder to be responsible for supplying a fixed percentage of the utility’s total load notwithstanding the customer’s classification. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Initial and reply comments on the proposal were filed by various parties in September and October 2007, respectively. The proposal is currently pending before the PUCO.

On April 22, 2008, an amended version of Substitute SB221 was passed by the Ohio House of Representatives and sent back to the Ohio Senate for concurrence. On April 23, 2008, the Ohio Senate approved the House's amendments to Substitute SB221 and forwarded the bill to the Governor for signature, which he signed on May 1, 2008. Amended Substitute SB221 requires all electric distribution utilities to file an RSP, now called an ESP, with the PUCO. An ESP is required to contain a proposal for the supply and pricing of retail generation and may include proposals, without limitation, related to one or more of the following:

·	automatic recovery of prudently incurred fuel, purchased power, emission allowance costs and federally mandated energy taxes;

·	construction work in progress for costs of constructing an electric generating facility or environmental expenditure for any electric generating facility;

·	costs of an electric generating facility;

·	terms related to customer shopping, bypassability, standby, back-up and default service;

·	accounting for deferrals related to stabilizing retail electric service;

·	automatic increases or decreases in standard service offer price;

·	phase-in and securitization;

·	transmission service and related costs;

·	distribution service and related costs; and

·	economic development and energy efficiency.

Pennsylvania

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.

Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October ~~15,~~2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.

On April 14, 2008, Met-Ed and Penelec filed annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The proposed TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed has proposed a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.

On March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. On April 14, 2008, the first RFP for residential customers’ load was held consisting of tranches for both 12 and 24-month supply. The PPUC approved the bids on April 16, 2008. The second RFP is scheduled to be held on May 14, 2008, after which time the PPUC is expected to approve the new rates to go into effect June 1, 2008.

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007, the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy. The final form of this pending legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

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 March 31, 2008, the accumulated deferred cost balance totaled approximately $264 million.

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

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 with comments from interested parties due on May 16, 2008.

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in the fall of 2006 and in early 2007.

On April 17, 2008, a draft EMP was released for public comment. The draft EMP establishes four major goals:

·	maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020;

·	reduce peak demand for electricity by 5,700 MW by 2020 (amounting to about a 22% reduction in projected demand);

·	meet 22.5% of the state’s electricity needs with renewable energy by 2020; and

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

Following the public comment period which is expected to extend into July 2008, a final EMP will be issued to be followed by appropriate legislation and regulation as necessary. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations or those of JCP&L.

On February 13, 2007, ~~FGCO completed~~the NJBPU Staff informally issued a ~~sale~~draft proposal relating to changes to the regulations addressing electric distribution service reliability and ~~leaseback transaction for its 93.825% undivided interest~~quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in ~~Bruce Mansfield Unit 1 (see Note 12). FES has unconditionally~~the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments that were submitted in September and ~~irrevocably guaranteed all of FGCO’s obligations under each~~October 2007. Final regulations (effective upon publication) were published in the New Jersey Register March 17, 2008. Upon preliminary review of the ~~leases. The related lessor notes and pass through certificates are~~new regulations, FirstEnergy does not ~~guaranteed by FES~~expect a material impact on its operations or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.those of JCP&L.

~~(B) ENVIRONMENTAL MATTERS~~FERC Matters

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate so-called “pancaking” of transmission charges between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the second quarter of 2008.

PJM Transmission Rate Design

On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission revenue recovery from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge. The FERC’s action on the settlement agreement is pending. The remaining merchant transmission cost allocation issues will proceed to hearing in May 2008. On February 13, 2008, AEP appealed the FERC’s orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.

Post Transition Period Rate Design

The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.

Distribution of MISO Network Service Revenues

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

Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be charged by MISO for network service. On February 2, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.

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

MISO Ancillary Services Market and Balancing Area Consolidation

MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. This filing would permit load serving entities to purchase their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. MISO has since notified the FERC that the start of its ASM is delayed until September of 2008.

Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join the MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.

On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne to pay the PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FirstEnergy and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed the MISO to submit detailed plans to integrate Duquesne into the MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into the MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 9, 2008.

On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators can contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfies the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. FirstEnergy is participating in the May 2008 RPM auction for the 2011-2012 RPM delivery year.

MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load serving entities in its state. FirstEnergy generally supports the proposal as it promotes a mechanism that will result in long-term commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC approved MISO’s Resource Adequacy proposal on March 26, 2008. Rehearing requests are pending on the FERC’s March 26 Order. A compliance filing establishing the enforcement mechanism for the reserve margin requirement is due on or before June 25, 2008.

Organized Wholesale Power Markets

On February 21, 2008, the FERC issued a NOPR through which it proposes to adopt new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FirstEnergy does not believe that the proposed rule will have a significant impact on its operations. Comments on the NOPR were filed on April 18, 2008.

Environmental Matters

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy estimates capital expenditures for environmental compliance of approximately ~~$1.8~~$1.4 billion for ~~2007 through 2011.~~the period 2008-2012.

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

Clean Air Act Compliance

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

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the ~~Clean Air Act.~~CAA. FirstEnergy has disputed those alleged violations based on its ~~Clean Air Act~~CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.

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

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal ~~Clean Air Act,~~CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the ~~Mansfield~~ Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October ~~16,~~18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim.

On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the Court. Although it remains liable for civil or criminal penalties and fines that may be assessed relating to events prior to the sale of the Portland Station in 1999, Met-Ed is ~~currently studying PennFuture’s complaint.~~indemnified by Sithe Energy against any other liability arising under the CAA whether it arises out of pre-1999 or post-1999 events.

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 ~~allowed each affected state until 2006 to develop implementing regulations to achieve additional~~requires reductions of NO_X and SO₂ emissions in two phases (Phase I in 2009 for NO_X, 2010 for SO₂ and Phase II in 2015 for both NO_X and SO₂). FirstEnergy's Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO₂ and NO_X emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on NO_X emissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. 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. CAIR has been challenged in the United States Court of Appeals for the District of Columbia. The future cost of compliance with these regulations may be substantial and ~~will~~may depend on the outcome of this litigation and how ~~they are~~CAIR is ultimately ~~implemented by the states in which FirstEnergy operates affected facilities.~~implemented.

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,~~phases; initially, capping national mercury emissions ~~will be capped nationally~~ at 38 tons by 2010 (as a "co-benefit" from implementation of SO₂ 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~~ and 15 tons per year by 2018. ~~However, the final rules give~~Several states ~~substantial discretion in developing rules to implement these programs. In addition, both the CAIR~~ and environmental groups appealed the CAMR ~~have been challenged in~~to the United States Court of Appeals for the District of Columbia. ~~FirstEnergy's~~On February 8, 2008, the court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap and trade program. The EPA must now seek further judicial review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with ~~these~~mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately ~~implemented by the states in which FirstEnergy operates affected facilities.~~implemented.

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. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.

W. H. Sammis Plant

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

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NO_X and SO₂ emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. 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 ~~settlement agreement~~consent decree are currently estimated to be ~~$1.7~~$1.3 billion for ~~2007 through 2011~~2008-2012 ($~~400~~650 million of which is expected to be spent during ~~2007,~~2008, with the largest portion of the remaining ~~$1.3 billion~~$650 million expected to be spent in ~~2008 and~~ 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The ~~Sammis NSR Litigation consent decree also requires FirstEnergy to spend up to $25 million toward environmentally beneficial projects, $14 million~~EPA has not yet issued a final regulation. FGCO’s future cost of ~~which is satisfied by entering into 93 MW (or 23 MW if federal tax credits~~compliance with those regulations may be substantial and will depend on how they 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.~~ultimately implemented.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG 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. AtAlso, in an April 16, 2008 speech, President Bush set a policy goal of stopping the ~~international level, efforts have begun to develop climate change agreements for post-2012~~growth of GHG ~~reductions. The~~emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United ~~States.~~States, and the Senate Environmental and Public Works Committees have passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO₂ emissions from automobiles as “air pollutants” under the ~~Clean Air Act.~~CAA. Although this decision did not address CO₂ emissions from electric generating plants, the EPA has similar authority under the ~~Clean Air Act~~CAA to regulate “air pollutants” from those and other facilities. Also on April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, the EPA proposed to change the NSR regulations, on May 8, 2007, to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.

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

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality ~~when~~(when aquatic organisms are pinned against screens or other parts of a cooling water intake ~~system,~~system) and entrainment ~~which~~(which occurs when aquatic life is drawn into a facility's cooling water ~~system.~~system). On January 26, 2007, the ~~federal~~United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review certain aspects of the Second Circuit’s decision. FirstEnergy is ~~evaluating~~studying various control options and their costs and effectiveness. Depending on the ~~outcome~~results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising BPJ, 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~~non-hazardous waste.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of ~~September 30, 2007,~~March 31, 2008, FirstEnergy had approximately ~~$1.5~~$2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and ~~Perry.~~TMI-2. As part of the application to the NRC to transfer the ownership of ~~these nuclear facilities~~Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” 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~~(and Exelon for TMI-1 as it relates to ~~seek~~the timing of the decommissioning of TMI-2) seeks 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~~may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of ~~September 30, 2007,~~March 31, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. ~~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 ~~$89~~$92 million (JCP&L - ~~$60~~$65 million, TE - $3$1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through ~~September 30, 2007.~~

March 31, 2008. Included in the total for JCP&L are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants in New Jersey; which are being recovered by JCP&L through a non-bypassable SBC.

~~(C) OTHER LEGAL PROCEEDINGS~~Other Legal Proceedings

Power Outages and Related Litigation

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior ~~Court.~~Court and a case management conference with the presiding Judge is scheduled for June 13, 2008. FirstEnergy is defending this class action but is unable to predict the outcome of this matter. No liability has been accrued as of ~~September 30, 2007.~~

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. – Canada Power System Outage Task 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.March 31, 2008.

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FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those 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. Two 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 cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc. (AEP), as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. 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. The four cases remaining were consolidated for hearing by the PUCO in an order dated March 7, 2006. In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled 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 January 8, 2008.

FirstEnergy is 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 May 14, 2007, the Office of Enforcement of the NRC issued a ~~Demand for Information~~DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information, about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s ~~Demand for Information~~DFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. ~~The NRC held~~FENOC submitted a ~~public meeting on June 27, 2007 with FENOC to discuss FENOC’s~~supplemental response ~~to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarify~~clarifying certain aspects of the ~~Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental~~DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC’s compliance with these commitments is subject to future NRC review.

Other Legal Matters

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

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint which OE ~~has~~ opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint.

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. ~~The arbitration panel provided additional rulings regarding damages during a September 2007 hearing and it is anticipated that he will issue a~~A final order ~~in late~~identifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal court to confirm the award and JCP&L ~~intends~~filed its answer and counterclaim to ~~re-file an appeal again~~vacate the award on December 31, 2007. The court held a scheduling conference in ~~federal district court once the damages associated~~April 2008 where it set a briefing schedule with ~~this case are identified at an individual employee level.~~all briefs to be concluded by July 2008. JCP&L recognized a liability for the potential $16 million award in 2005.

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

FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

~~11. REGULATORY MATTERS~~

~~(A) RELIABILITY INITIATIVES~~

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (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. 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 served, among other things, partly to amend the Federal Power Act by adding a new Section 215, which requires that a new ERO establish and enforce reliability standards for the bulk-power system, subject to review by the FERC. Subsequently, the FERC certified NERC as the ERO, approved NERC's Compliance Monitoring and Enforcement Program and approved a set of reliability standards, which became mandatory and enforceable on June 18, 2007 with penalties and sanctions for noncompliance. The FERC also approved a delegation agreement between NERC and Reliability~~First~~ ~~Corporation, one of eight Regional Entities that carry out enforcement for NERC. All of FirstEnergy’s facilities are located within the Reliability~~~~First~~ ~~region.~~

To date, FERC has approved 83 of the 107 reliability standards proposed by NERC. Nevertheless, the FERC has directed NERC to submit improvements to 56 of the 83 approved standards and has endorsed NERC's process for developing reliability standards and its associated work plan. On May 4, 2007, NERC submitted 24 proposed Violation Risk Factors that would operate as a system of weighting the risk to the power grid associated with a particular reliability standard violation. The FERC issued an order approving 22 of those factors on June 26, 2007. Further, NERC adopted eight cyber security standards and filed them with the FERC for approval. On December 11, 2006, the FERC Staff provided its preliminary assessment of the cyber security standards and cited various deficiencies in the proposed standards. Numerous parties, including FirstEnergy, provided comments on the preliminary assessment. The standards remain pending before the FERC. Separately, on July 20, 2007, the FERC issued a NOPR proposing to adopt eight related Critical Infrastructure Protection Reliability Standards. On October 5, 2007, numerous parties, including FirstEnergy, provided comments on the proposed Critical Infrastructure Protection standards. These standards, and FirstEnergy’s comments thereon, are pending before FERC.

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FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the FERC's guidance to NERC in its March 16, 2007 Final Rule on Mandatory Reliability Standards, it appears that the FERC may eventually adopt stricter standards than those just approved. 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 April 18-20, 2007, Reliabilit~~~~yFirst~~ performed a routine compliance audit of FirstEnergy's bulk-power system within the Midwest ISO region and found FirstEnergy to be in full compliance with all audited reliability standards. Similarly, Reliability~~First~~ has scheduled a compliance audit of FirstEnergy's bulk-power system within the PJM region in 2008. FirstEnergy does not expect any material adverse impact to its financial condition as a result of these audits.

~~(B) OHIO~~

On September 9, 2005, the Ohio Companies filed their RCP with the PUCO. The filing included a stipulation and supplemental stipulation with several parties agreeing to the provisions set forth in the plan. On January 4, 2006, the PUCO issued an order which approved the stipulation on the RCP after clarifying certain provisions. Several parties subsequently filed appeals to the Supreme Court of Ohio in connection with certain portions of the RCP approved by the PUCO. In its order, the PUCO authorized the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs, all such costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a 25-year period through distribution rates, which was expected to begin on January 1, 2009 for OE and TE, and approximately May 2009 for CEI. Through September 30, 2007, the deferred fuel costs, including interest, were $89 million, $61 million and $26 million for OE, CEI and TE, respectively.

On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated certain provisions of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” because fuel costs are a component of generation service, not distribution service, and because the Court concluded the PUCO did not address whether the deferral of fuel costs was anticompetitive. The Court remanded the matter to the PUCO for further consideration consistent with the Court’s Opinion on this issue and affirmed the PUCO’s Order in all other respects. On September 7, 2007, the Ohio Companies filed a Motion for Reconsideration with the Court. On September 10, 2007 the Ohio Companies filed an Application with the PUCO that requests the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. The Ohio Companies requested the riders become effective in October 2007 and end in December 2008, subject to reconciliation which is expected to continue through the first quarter of 2009. This matter is currently pending before the PUCO. Although unable to predict the ultimate outcome of this matter, the Ohio Companies intend to continue deferring the fuel costs pursuant to the RCP, pending the Court’s disposition of the Motion for Reconsideration and the PUCO’s action with respect to the Ohio Companies’ Application.

On August 31, 2005, the PUCO approved a rider recovery mechanism through which the Ohio Companies may recover all MISO transmission and ancillary service related costs incurred during each year ending June 30. Pursuant to the PUCO’s order, the Ohio Companies, on May 1, 2007, filed revised riders, which became effective on July 1, 2007. The revised riders represent an increase over the amounts collected through the 2006 riders of approximately $64 million annually. If it is subsequently determined by the PUCO that adjustments to the rider as filed are necessary, such adjustments, with carrying costs, will be incorporated into the 2008 transmission rider filing.

On May 8, 2007, the Ohio Companies filed with the PUCO a notice of intent to file for an increase in electric distribution rates. The Ohio Companies filed the application and rate request with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operating and maintenance expenses and recovery of regulatory assets created by deferrals that were approved in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million to the PUCO to establish the test period data that will be used as the basis for setting rates in that proceeding. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in early 2008. The PUCO order is expected to be issued in the second quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Comments by intervenors in the case were filed on September 5, 2007. The PUCO Staff filed comments on September 21, 2007. Parties filed reply comments on October 12, 2007. The Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process.

On September 25, 2007, the Ohio Governor’s proposed energy plan was officially introduced into the Ohio Senate. The bill proposes to revise state energy policy to address electric generation pricing after 2008, establish advanced energy portfolio standards and energy efficiency standards, and create GHG emissions reporting and carbon control planning requirements. The bill also proposes to move to a “hybrid” system for determining rates for PLR service in which electric utilities would provide regulated generation service unless they satisfy a statutory burden to demonstrate the existence of a competitive market for retail electricity. The Senate Energy & Public Utilities Committee has been conducting hearings on the bill and receiving testimony from interested parties, including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer groups, utility executives and others. Several proposed amendments to the bill have been submitted, including those from Ohio’s investor-owned electric utilities. A substitute version of the bill, which incorporated certain of the proposed amendments, was introduced into the Senate Energy & Public Utilities Committee on October 25, 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of the Ohio Companies.

~~(C) PENNSYLVANIA~~

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 requirements during the term of these agreements with FES.

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 were substantially higher than the fixed price in the partial requirements agreements.

Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.

If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for 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 transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec 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. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

The PPUC entered its Opinion and Order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, when new transmission rates were effective, 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 transmission deferral. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC 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 of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part the MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. On June 19, 2007, initial briefs were filed and responsive briefs were filed through September 21, 2007. Reply briefs were filed on October 5, 2007. Oral arguments are expected to take place in late 2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the financial condition and results of operations of Met-Ed, Penelec and FirstEnergy.

As of September 30, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $496 million and $58 million, respectively. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in February 2007 and briefing was completed on March 28, 2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.

On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service will be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. On September 28, 2007, Penn filed a Joint Petition for Settlement resolving all but one issue in the case. Briefs were also filed on September 28, 2007 on the unresolved issue of incremental uncollectible accounts expense. The settlement is either supported, or not opposed, by all parties. The PPUC is expected to act on the settlement and the unresolved issue in late November or early December 2007 for the initial RFP to take place in January 2008.

~~(D) NEW JERSEY~~

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2007, the accumulated deferred cost balance totaled approximately $330 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further 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 Staff circulated a revised draft proposal to interested stakeholders. Another revised draft was circulated by the NJBPU Staff on February 8, 2007.

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated 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 New Jersey’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;~~

·	~~Maintain unit prices for electricity to 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 obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing (1) energy efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing issues have completed their assigned tasks of data gathering and analysis and have provided reports to the EMP Committee. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected later in 2007. A final draft of the EMP is expected to be presented to the Governor in late 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of JCP&L.

On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments which were due on September 26, 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such regulations may have on its operations or those of JCP&L.

~~(E) FERC MATTERS~~

On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES 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 the fourth quarter of 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 & Electric Company (BG&E) and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. Hearings were held and numerous parties appeared and litigated various issues; including AEP, which filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. At the conclusion of the hearings, the ALJ issued an initial decision adopting 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. Numerous parties, including FirstEnergy, submitted briefs opposing the ALJ’s decision and recommendations. On April 19, 2007, the FERC issued an order rejecting the ALJ’s findings and recommendations in nearly every respect. The FERC found that the PJM transmission owners’ existing “license plate” rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be socialized throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. Nevertheless, the FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 Order. Subsequently, FirstEnergy and other parties filed pleadings opposing the requests for rehearing. The FERC’s Orders on PJM rate design, if sustained on rehearing and appeal, will prevent the allocation of the cost of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission costs shifting to the JCP&L, Met-Ed and Penelec zones.

~~New FERC Transmission Rate Design Filings~~

On August 1, 2007, a number of filings were made with the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.

FirstEnergy joined in a filing made by the MISO transmission owners that would maintain the existing “license plate” rates for transmission service within MISO provided over existing transmission facilities. FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to continue the elimination of transmission rates associated with service over existing transmission facilities between MISO and PJM. If adopted by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint be maintained (known as the RECB Process). Each of these filings was supported by the majority of transmission owners in either MISO or PJM, as applicable.

The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV and higher transmission facilities be spread throughout the entire MISO footprint. Further, Indianapolis Power and Light Company separately moved the FERC to reopen the record to address the cost allocation for the RECB Process. If either proposal is adopted by the FERC, it could shift a greater portion of the cost of new 345 kV and higher transmission facilities to the FirstEnergy footprint in MISO, and increase the transmission rates paid by load-serving FirstEnergy affiliates in MISO.

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “SuperRegion” that regionalizes the cost of new and existing transmission facilities operated at voltages of 345 kV and above. Lower voltage facilities would continue to be recovered in the host utility transmission rate zone through a license plate rate. AEP requests a refund effective October 1, 2007, or alternatively, February 1, 2008. The effect of this proposal, if adopted by FERC, would be to shift significant costs to the FirstEnergy zones in MISO and PJM. FirstEnergy believes that most of these costs would ultimately be recoverable in retail rates. On October 12, 2007, BG&E filed a motion to dismiss AEP’s complaint. On October 16, 2007, the Organization of MISO States filed comments urging the FERC to dismiss AEP’s complaint. Interventions and protests to AEP’s complaint and answers to BG&E’s motion to dismiss were due October 29, 2007. FirstEnergy and other transmission owners filed protests to AEP’s complaint and support for BG&E’s motion to dismiss. AEP has asked for consolidation of its complaint with the cases above, and FirstEnergy expects it to be resolved on the same timeline as those cases.

Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC. All or some of these proceedings may be consolidated by the FERC and set for hearing. The outcome of these cases cannot be predicted. Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates. FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates. Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.

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

MISO made a filing on September 14, 2007 to establish Ancillary Services markets for regulation, spinning and supplemental reserves to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. An effective date of June 1, 2008 was requested in the filing.

MISO’s previous filing to establish an Ancillary Services market was rejected without prejudice by FERC on June 22, 2007, subject to MISO making certain modifications in its filing. FirstEnergy believes that MISO’s September 14 filing generally addresses the FERC’s directives. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas, but filed objections on specific aspects of the MISO proposal. Interventions and protests to MISO’s filing were made with FERC on October 15, 2007.

~~Order No. 890 on Open Access Transmission Tariffs~~

On February 16, 2007, the FERC issued a final rule (Order No. 890) 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 became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffs to comply with the FERC’s order. MISO, PJM and ATSI submitted tariff filings to the FERC on October 11, 2007. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.

~~12. LEASES~~

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion (net after-tax proceeds of approximately $1.2 billion) for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034. A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates. The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. FES’ registration obligations under the registration rights agreement applicable to the $1.135 billion principal amount of pass through certificates issued in connection with the transaction were satisfied in September 2007, at which time the transaction was classified as an operating lease under GAAP for FES and FirstEnergy. This transaction generated tax capital gains of approximately $752 million, all of which were offset by existing tax capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowances in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 3).

~~The future minimum lease payments associated with the recently completed Bruce Mansfield Unit 1 sale and leaseback transaction as of September 30, 2007 are as follows (in millions):~~

2007 $ 44
2008 89
2009 89
2010 89
2011 89
Years thereafter 2,286
Total minimum lease payments $ 2,686

~~13.~~ NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS ~~157~~141(R) – ~~“Fair Value Measurements”~~“Business Combinations”

In ~~September 2006,~~December 2007, the FASB issued SFAS ~~157 that~~141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes ~~how companies should measure~~the acquisition-date fair value ~~when~~as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they ~~are required~~need to ~~use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses~~evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for ~~increased consistency~~numerous EITF issues and ~~comparability~~other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in ~~fair value measurements and for expanded disclosures about fair value measurements. The key changes~~tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to ~~current practice are: (1)~~ the ~~definition~~implementation 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.this Standard. FirstEnergy is currently evaluating the impact of adopting this ~~Statement~~Standard on its financial statements.

SFAS 160 - “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”

~~SFAS 159 – “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of~~

~~FASB Statement No. 115”~~

In ~~February~~December 2007, the FASB issued SFAS ~~159, which provides companies with~~160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ~~option to report selected~~ownership interest in the consolidated entity that should be reported as equity in the consolidated financial assets and liabilities at fair value. This Statement 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~~and SFAS 107~~. statements. This Statement is effective for ~~financial statements issued for~~ fiscal years, ~~beginning after November 15, 2007,~~ and interim periods within those ~~years.~~fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FirstEnergy’s financial statements.

SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”

In March 2008, the FASB issued SFAS 161, which enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This disclosure better conveys the purpose of derivative use in terms of the risks that the entity is intending to manage. The FASB believes disclosing the fair values of derivative instruments and their gains and losses in a tabular format is designed to provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. Finally, this Statement requires cross-referencing within the footnotes, which is intended to help users of financial statements locate important information about derivative instruments. FirstEnergy is currently evaluating the impact of adopting this ~~Statement~~Standard on its financial statements.

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

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

~~FSP FIN 39-1 – “Amendment of FASB Interpretation No. 39”~~

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

~~14. SEGMENT INFORMATION~~

Effective January 1, 2007, FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. None of the aggregate “Other” segments individually meet the criteria to be considered a reportable segment. The energy delivery services segment consists of regulated transmission and distribution operations, including transition cost recovery, and PLR generation service for FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. The competitive energy services segment primarily consists of unregulated generation and commodity operations, including competitive electric sales, and generation sales to affiliated electric utilities. The Ohio transitional generation services segment represents PLR generation service by FirstEnergy’s Ohio electric utility subsidiaries. “Other” primarily consists of telecommunications services and other non-core assets. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”

The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. Its revenues are primarily derived from the delivery of electricity, cost recovery of regulatory assets and PLR electric generation sales to non-shopping customers in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under partial requirements purchased power agreements and non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.

The competitive energy services segment supplies electric power to its electric utility affiliates and competitive electric sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. The segment owns or leases and operates FirstEnergy’s generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from the affiliated company power sales and the non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment’s customers. The segment’s internal revenues represent the affiliated company power sales.

The Ohio transitional generation services segment represents the regulated generation operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect the purchase of electric generation from the competitive energy services segment through full requirements PSA arrangements, the deferral and amortization of certain fuel costs authorized for recovery by the energy delivery services segment and the net MISO transmission revenues and expenses related to the delivery of its generation load. This segment’s total assets consist of accounts receivable for generation revenues from retail customers.

Segment reporting in 2006 has been revised to conform to the current year business segment organization and operations. Changes in the current year operations reporting and revised 2006 segment reporting primarily reflect the transfer from FES to the regulated utilities of the responsibility for obtaining PLR generation for the utilities’ non-shopping customers. This reflects FirstEnergy’s alignment of its business units to accommodate its retail strategy and participation in competitive electricity marketplaces in Ohio, Pennsylvania and New Jersey. The differentiation of the regulated generation commodity operations between the two regulated business segments recognizes that generation sourcing for the Ohio Companies is currently in a transitional state through 2008 as compared to the segregated commodity sourcing of their Pennsylvania and New Jersey utility affiliates. The results of the energy delivery services and the Ohio transitional generation services segments now include their electric generation revenues and the corresponding generation commodity costs under affiliated and non-affiliated purchased power arrangements and related net retail PJM/MISO transmission expenses associated with serving electricity load in their respective franchise areas.

FSG completed the sale of its five remaining subsidiaries in 2006. Its assets and results for 2006 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 Adjustments."

Segment Financial Information

Ohio

Energy

Competitive

Transitional

Delivery

Energy

Generation

Reconciling

Three Months Ended

Services

Services

Services

Other

Adjustments

Consolidated

(In millions)

September 30, 2007

External revenues $ 2,520 $ 370 $ 723 $ 9 $ 19 $ 3,641
Internal revenues - 806 - - (806 ) -
Total revenues 2,520 1,176 723 9 (787 ) 3,641
Depreciation and amortization 299 51 (16 ) 1 8 343
Investment income 58 5 - 1 (34 ) 30
Net interest charges 117 39 - 1 37 194
Income taxes 175 99 11 (2 ) (10 ) 273
Net income 269 148 16 6 (26 ) 413
Total assets 23,308 7,182 268 232 663 31,653
Total goodwill 5,585 24 - - - 5,609
Property additions 209 199 - 1 21 430

September 30, 2006

External revenues $ 2,306 $ 353 $ 690 $ 24 $ (9 ) $ 3,364
Internal revenues - 762 - - (762 ) -
Total revenues 2,306 1,115 690 24 (771 ) 3,364
Depreciation and amortization 227 49 (40 ) 1 6 243
Investment income 80 18 - - (52 ) 46
Net interest charges 107 49 - 2 22 180
Income taxes 187 112 18 (14 ) (30 ) 273
Income from
continuing operations 280 169 27 25 (49 ) 452
Discontinued operations - - - 2 - 2
Net income 280 169 27 27 (49 ) 454
Total assets 23,940 6,822 240 321 839 32,162
Total goodwill 5,911 24 - - - 5,935
Property additions 119 126 - - 6 251

Nine Months Ended

September 30, 2007

External revenues $ 6,655 $ 1,089 $ 1,968 $ 29 $ (18 ) $ 9,723
Internal revenues - 2,210 - - (2,210 ) -
Total revenues 6,655 3,299 1,968 29 (2,228 ) 9,723
Depreciation and amortization 767 153 (80 ) 3 20 863
Investment income 190 13 1 1 (112 ) 93
Net interest charges 340 131 1 3 97 572
Income taxes 464 259 46 - (74 ) 695
Net income 695 388 69 13 (124 ) 1,041
Total assets 23,308 7,182 268 232 663 31,653
Total goodwill 5,585 24 - - - 5,609
Property additions 609 462 - 4 52 1,127

September 30, 2006

External revenues $ 5,876 $ 1,077 $ 1,808 $ 92 $ (32 ) $ 8,821
Internal revenues 14 1,997 - - (2,011 ) -
Total revenues 5,890 3,074 1,808 92 (2,043 ) 8,821
Depreciation and amortization 657 143 (89 ) 3 17 731
Investment income 244 35 - 1 (160 ) 120
Net interest charges 308 139 1 5 60 513
Income taxes 468 201 58 (17 ) (85 ) 625
Income from
continuing operations 702 302 88 30 (139 ) 983
Discontinued operations - - - (4 ) - (4 )
Net income 702 302 88 26 (139 ) 979
Total assets 23,940 6,822 240 321 839 32,162
Total goodwill 5,911 24 - - - 5,935
Property additions 489 473 - - 28 990

Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses and elimination of intersegment transactions.

~~15. SUPPLEMENTAL GUARANTOR INFORMATION~~

As discussed in Note 12, on July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.

The consolidating statements of income for the three months and nine months ended September 30, 2007 and 2006, consolidating balance sheets as of September 30, 2007 and December 31, 2006 and condensed consolidating statements of cash flows for the nine months ended September 30, 2007 and 2006 for FES (parent), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and reflect the consolidating entries associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME

(Unaudited)

For the Three Months Ended September 30, 2007

FES

FGCO

NGC

Eliminations

Consolidated

(In thousands)

REVENUES
$ 1,180,449 $ 496,204 $ 280,072 $ (785,817 ) $ 1,170,908

EXPENSES:

Fuel 10,944 261,759 29,083 - 301,786
Purchased power from non-affiliates 228,755 - - - 228,755
Purchased power from affiliates 774,873 57,927 15,525 (785,817 ) 62,508
Other operating expenses 41,828 75,985 117,220 - 235,033
Provision for depreciation 650 24,669 23,181 - 48,500
General taxes 5,406 11,788 5,048 - 22,242
Total expenses 1,062,456 432,128 190,057 (785,817 ) 898,824

OPERATING INCOME
117,993 64,076 90,015 - 272,084

OTHER INCOME (EXPENSE):

Miscellaneous income (expense), including
net income from equity investees 82,870 2,375 3,935 (76,525 ) 12,655
Interest expense to affiliates (676 ) (4,769 ) (4,196 ) - (9,641 )
Interest expense - other (808 ) (21,274 ) (9,712 ) - (31,794 )
Capitalized interest 9 3,889 1,233 - 5,131
Total other income (expense) 81,395 (19,779 ) (8,740 ) (76,525 ) (23,649 )

INCOME BEFORE INCOME TAXES
199,388 44,297 81,275 (76,525 ) 248,435

INCOME TAXES
44,624 19,850 29,197 - 93,671

NET INCOME
$ 154,764 $ 24,447 $ 52,078 $ (76,525 ) $ 154,764

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME

(Unaudited)

For the Three Months Ended September 30, 2006

FES

FGCO

NGC

Eliminations

Consolidated

(In thousands)

REVENUES
$ 1,120,844 $ 466,628 $ 246,039 $ (723,931 ) $ 1,109,580

EXPENSES:

Fuel 12,632 273,398 29,491 - 315,521
Purchased power from non-affiliates 173,620 - - - 173,620
Purchased power from affiliates 711,298 52,062 16,218 (723,931 ) 55,647
Other operating expenses 42,115 48,728 107,873 - 198,716
Provision for depreciation 456 24,656 21,782 - 46,894
General taxes 3,223 8,931 5,455 - 17,609
Total expenses 943,344 407,775 180,819 (723,931 ) 808,007

OPERATING INCOME
177,500 58,853 65,220 - 301,573

OTHER INCOME (EXPENSE):

Miscellaneous income (expense), including
net income from equity investees 69,102 1,694 18,089 (61,223 ) 27,662
Interest expense to affiliates - (29,988 ) (11,428 ) - (41,416 )
Interest expense - other (207 ) (2,749 ) (4,958 ) - (7,914 )
Capitalized interest 5 1,217 1,167 - 2,389
Total other income (expense) 68,900 (29,826 ) 2,870 (61,223 ) (19,279 )

INCOME BEFORE INCOME TAXES
246,400 29,027 68,090 (61,223 ) 282,294

INCOME TAXES
70,281 10,134 25,760 - 106,175

NET INCOME
$ 176,119 $ 18,893 $ 42,330 $ (61,223 ) $ 176,119

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME

(Unaudited)

For the Nine Months Ended September 30, 2007

FES

FGCO

NGC

Eliminations

Consolidated

(In thousands)

REVENUES
$ 3,274,694 $ 1,501,112 $ 793,255 $ (2,311,129 ) $ 3,257,932

EXPENSES:

Fuel 20,824 698,643 84,734 - 804,201
Purchased power from non-affiliates 577,831 - - - 577,831
Purchased power from affiliates 2,290,305 176,654 53,746 (2,311,129 ) 209,576
Other operating expenses 123,596 240,774 367,404 - 731,774
Provision for depreciation 1,572 74,844 68,614 - 145,030
General taxes 15,942 31,406 17,522 - 64,870
Total expenses 3,030,070 1,222,321 592,020 (2,311,129 ) 2,533,282

OPERATING INCOME
244,624 278,791 201,235 - 724,650

OTHER INCOME (EXPENSE):

Miscellaneous income (expense), including
net income from equity investees 271,599 2,669 13,350 (239,862 ) 47,756
Interest expense to affiliates (676 ) (47,090 ) (14,138 ) - (61,904 )
Interest expense - other (7,966 ) (34,150 ) (28,729 ) - (70,845 )
Capitalized interest 20 9,044 3,699 - 12,763
Total other income (expense) 262,977 (69,527 ) (25,818 ) (239,862 ) (72,230 )

INCOME BEFORE INCOME TAXES
507,601 209,264 175,417 (239,862 ) 652,420

INCOME TAXES
98,917 82,031 62,788 - 243,736

NET INCOME
$ 408,684 $ 127,233 $ 112,629 $ (239,862 ) $ 408,684

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME

(Unaudited)

For the Nine Months Ended September 30, 2006

FES

FGCO

NGC

Eliminations

Consolidated

(In thousands)

REVENUES
$ 3,071,970 $ 1,336,076 $ 797,967 $ (2,145,891 ) $ 3,060,122

EXPENSES:

Fuel 16,650 752,229 76,034 - 844,913
Purchased power from non-affiliates 477,249 - - - 477,249
Purchased power from affiliates 2,143,509 141,974 49,106 (2,145,891 ) 188,698
Other operating expenses 149,042 204,282 421,443 - 774,767
Provision for depreciation 1,314 72,778 61,322 - 135,414
General taxes 9,268 29,536 16,746 - 55,550
Total expenses 2,797,032 1,200,799 624,651 (2,145,891 ) 2,476,591

OPERATING INCOME
274,938 135,277 173,316 - 583,531

OTHER INCOME (EXPENSE):

Miscellaneous income (expense), including
net income from equity investees 146,375 (3,052 ) 35,518 (133,998 ) 44,843
Interest expense to affiliates (241 ) (87,318 ) (35,105 ) - (122,664 )
Interest expense - other (564 ) (5,650 ) (11,666 ) - (17,880 )
Capitalized interest (3 ) 3,290 5,411 - 8,698
Total other income (expense) 145,567 (92,730 ) (5,842 ) (133,998 ) (87,003 )

INCOME BEFORE INCOME TAXES
420,505 42,547 167,474 (133,998 ) 496,528

INCOME TAXES
108,549 13,296 62,727 - 184,572

NET INCOME
$ 311,956 $ 29,251 $ 104,747 $ (133,998 ) $ 311,956

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of September 30, 2007

FES

FGCO

NGC

Eliminations

Consolidated

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 2 $ - $ - $ - $ 2
Receivables-
Customers 144,443 - - - 144,443
Associated companies 282,118 169,108 113,936 (279,700 ) 285,462
Other 4,862 554 - - 5,416
Notes receivable from associated companies - 242,612 - - 242,612
Materials and supplies, at average cost 195 224,149 216,722 - 441,066
Prepayments and other 67,892 13,693 2,240 - 83,825
499,512 650,116 332,898 (279,700 ) 1,202,826

PROPERTY, PLANT AND EQUIPMENT:

In service 25,171 5,023,255 3,530,969 (395,817 ) 8,183,578
Less - Accumulated provision for depreciation 6,807 2,539,192 1,476,051 (169,154 ) 3,852,896
18,364 2,484,063 2,054,918 (226,663 ) 4,330,682
Construction work in progress 1,034 414,243 181,602 - 596,879
19,398 2,898,306 2,236,520 (226,663 ) 4,927,561

INVESTMENTS:

Nuclear plant decommissioning trusts - - 1,342,083 - 1,342,083
Long-term notes receivable from associated companies - - 62,900 - 62,900
Investment in associated companies 2,462,960 - - (2,462,960 ) -
Other 5,315 34,447 202 - 39,964
2,468,275 34,447 1,405,185 (2,462,960 ) 1,444,947

DEFERRED CHARGES AND OTHER ASSETS:

Accumulated deferred income taxes 28,756 403,890 - (192,464 ) 240,182
Goodwill 24,248 - - - 24,248
Property taxes - 20,946 23,165 - 44,111
Pension assets 1,154 8,295 - - 9,449
Other 33,049 32,477 5,112 - 70,638
87,207 465,608 28,277 (192,464 ) 388,628
$ 3,074,392 $ 4,048,477 $ 4,002,880 $ (3,161,787 ) $ 7,963,962

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ - $ 624,517 $ 861,265 $ (16,061 ) $ 1,469,721
Notes payable-
Associated companies 223,942 - 13,128 - 237,070
Other - - - - -
Accounts payable-
Associated companies 279,976 158,500 273,919 (279,700 ) 432,695
Other 65,782 112,038 - - 177,820
Accrued taxes 44,995 461,635 30,430 - 537,060
Other 60,252 59,770 9,731 33,486 163,239
674,947 1,416,460 1,188,473 (262,275 ) 3,017,605

CAPITALIZATION:

Common stockholder's equity 2,369,019 905,100 1,557,860 (2,462,960 ) 2,369,019
Long-term debt - 1,575,653 242,400 (1,312,857 ) 505,196
2,369,019 2,480,753 1,800,260 (3,775,817 ) 2,874,215

NONCURRENT LIABILITIES:

Deferred gain on sale and leaseback transaction - - - 1,068,769 1,068,769
Accumulated deferred income taxes - - 192,464 (192,464 ) -
Accumulated deferred investment tax credits - 36,764 25,511 - 62,275
Asset retirement obligations - 24,350 773,007 - 797,357
Retirement benefits 7,843 45,662 - - 53,505
Property taxes - 21,268 23,165 - 44,433
Other 22,583 23,220 - - 45,803
30,426 151,264 1,014,147 876,305 2,072,142
$ 3,074,392 $ 4,048,477 $ 4,002,880 $ (3,161,787 ) $ 7,963,962

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of December 31, 2006

FES

FGCO

NGC

Eliminations

Consolidated

(In thousands)

ASSETS

CURRENT ASSETS:

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

PROPERTY, PLANT AND EQUIPMENT:

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

INVESTMENTS:

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

DEFERRED CHARGES AND OTHER ASSETS:

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

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

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

CAPITALIZATION:

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

NONCURRENT LIABILITIES:

Accumulated deferred income taxes - 25,293 129,095 (32,939 ) 121,449
Accumulated deferred investment tax credits - 38,894 26,857 - 65,751
Asset retirement obligations - 24,272 735,956 - 760,228
Retirement benefits 10,255 92,772 - - 103,027
Property taxes - 21,268 23,165 - 44,433
Other 26,045 5,780 - - 31,825
36,300 208,279 915,073 (32,939 ) 1,126,713
$ 2,408,298 $ 3,163,825 $ 4,127,472 $ (1,700,588 ) $ 7,999,007

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Nine Months Ended September 30, 2007

FES

FGCO

NGC

Eliminations

Consolidated

(In thousands)

NET CASH PROVIDED FROM (USED FOR)

OPERATING ACTIVITIES
$ (17,080 ) $ 350,927 $ 146,468 $ - $ 480,315

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt - 1,328,919 - (1,328,919 ) -
Equity contribution from parent 710,468 700,000 1,325 (701,325 ) 710,468
Short-term borrowings, net 223,942 - 13,128 (237,070 ) -
Redemptions and Repayments-
Long-term debt - (795,019 ) (315,155 ) - (1,110,174 )
Short-term borrowings, net - (1,022,197 ) - 237,070 (785,127 )
Common stock (600,000 ) - - - (600,000 )
Common stock dividend payments (67,000 ) - - - (67,000 )
Net cash provided from (used for) financing activities 267,410 211,703 (300,702 ) (2,030,244 ) (1,851,833 )

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (10,119 ) (332,499 ) (140,289 ) - (482,907 )
Proceeds from asset sales - 12,990 - - 12,990
Proceeds from sale and leaseback transaction - - - 1,328,919 1,328,919
Sales of investment securities held in trusts - - 521,535 - 521,535
Purchases of investment securities held in trusts - - (521,535 ) - (521,535 )
Loan repayments from (loans to) associated companies, net 460,023 (242,612 ) 292,896 - 510,307
Investment in subsidiary (701,325 ) - - 701,325 -
Other 1,091 (509 ) 1,627 - 2,209
Net cash provided from (used for) investing activities (250,330 ) (562,630 ) 154,234 2,030,244 1,371,518

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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Nine Months Ended September 30, 2006

FES

FGCO

NGC

Eliminations

Consolidated

(In thousands)

NET CASH PROVIDED FROM

OPERATING ACTIVITIES
$ 145,390 $ 72,860 $ 239,855 $ - $ 458,105

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt - 146,704 105,241 - 251,945
Short-term borrowings, net - 66,817 - - 66,817
Redemptions and Reyapments-
Long-term debt - (146,740 ) (106,500 ) - (253,240 )
Net cash provided from financing activities - 66,781 (1,259 ) - 65,522

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (699 ) (131,853 ) (294,746 ) - (427,298 )
Proceeds from asset sales - 20,437 - - 20,437
Sales of investment securities held in trusts - - 886,863 - 886,863
Purchases of investment securities held in trusts - - (886,863 ) - (886,863 )
Loans to associated companies (145,734 ) - 57,442 - (88,292 )
Other 1,043 (28,225 ) (1,292 ) - (28,474 )
Net cash used for investing activities (145,390 ) (139,641 ) (238,596 ) - (523,627 )

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

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2007

2006

2007

2006

(In millions, except per share amounts)

REVENUES:

Electric utilities $ 3,260 $ 2,996 $ 8,685 $ 7,677
Unregulated businesses 381 368 1,038 1,144
Total revenues * 3,641 3,364 9,723 8,821

EXPENSES:

Fuel and purchased power 1,495 1,317 3,801 3,306
Other operating expenses 756 758 2,255 2,230
Provision for depreciation 162 153 477 445
Amortization of regulatory assets 288 243 785 665
Deferral of new regulatory assets (107 ) (153 ) (399 ) (379 )
General taxes 197 187 589 553
Total expenses 2,791 2,505 7,508 6,820

OPERATING INCOME
850 859 2,215 2,001

OTHER INCOME (EXPENSE):

Investment income 30 46 93 120
Interest expense (203 ) (185 ) (593 ) (528 )
Capitalized interest 9 7 21 21
Subsidiaries’ preferred stock dividends - (2 ) - (6 )
Total other expense (164 ) (134 ) (479 ) (393 )

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
686 725 1,736 1,608

INCOME TAXES
273 273 695 625

INCOME FROM CONTINUING OPERATIONS
413 452 1,041 983

Discontinued operations (net of income tax benefits of
$1 million and $2 million in the three months and
nine months ended September 30, 2006, respectively) (Note 4) - 2 - (4 )

NET INCOME
$ 413 $ 454 $ 1,041 $ 979

BASIC EARNINGS PER SHARE OF COMMON STOCK:

Income from continuing operations $ 1.36 $ 1.40 $ 3.39 $ 3.00
Discontinued operations - 0.01 - (0.01 )
Net earnings per basic share $ 1.36 $ 1.41 $ 3.39 $ 2.99

WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
304 322 307 326

DILUTED EARNINGS PER SHARE OF COMMON STOCK:

Income from continuing operations $ 1.34 $ 1.39 $ 3.35 $ 2.98
Discontinued operations - 0.01 - (0.01 )
Net earnings per diluted share $ 1.34 $ 1.40 $ 3.35 $ 2.97

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
307 325 311 329

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
$ 1.00 $ 0.45 $ 1.50 $ 1.35

* Includes excise tax collections of $108 million in the third quarter of both 2007 and 2006, and $308 million and $297 million in the nine
months ended September 2007 and 2006, respectively.

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2007

2006

2007

2006

(In millions)

NET INCOME
$ 413 $ 454 $ 1,041 $ 979

OTHER COMPREHENSIVE INCOME (LOSS):

Pension and other postretirement benefits (12 ) - (34 ) -
Unrealized gain (loss) on derivative hedges (10 ) (28 ) 10 45
Change in unrealized gain on available for sale securities 26 26 89 39
Other comprehensive income (loss) 4 (2 ) 65 84
Income tax expense (benefit) related to other
comprehensive income - (1 ) 19 30
Other comprehensive income (loss), net of tax 4 (1 ) 46 54

COMPREHENSIVE INCOME
$ 417 $ 453 $ 1,087 $ 1,033

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

September 30,

December 31,

2007

2006

(In millions)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 30 $ 90
Receivables-
Customers (less accumulated provisions of $38 million and
$43 million, respectively, for uncollectible accounts) 1,432 1,135
Other (less accumulated provisions of $22 million and
$24 million, respectively, for uncollectible accounts) 194 132
Materials and supplies, at average cost 543 577
Prepayments and other 207 149
2,406 2,083
PROPERTY, PLANT AND EQUIPMENT:

In service 24,353 24,105
Less - Accumulated provision for depreciation 10,248 10,055
14,105 14,050
Construction work in progress 933 617
15,038 14,667
INVESTMENTS:

Nuclear plant decommissioning trusts 2,140 1,977
Investments in lease obligation bonds 738 811
Other 787 746
3,665 3,534
DEFERRED CHARGES AND OTHER ASSETS:

Goodwill 5,609 5,898
Regulatory assets 4,047 4,441
Pension assets 318 -
Other 570 573
10,544 10,912
$ 31,653 $ 31,196
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ 2,265 $ 1,867
Short-term borrowings 573 1,108
Accounts payable 760 726
Accrued taxes 671 598
Accrued interest 215 111
Other 894 845
5,378 5,255
CAPITALIZATION:

Common stockholders’ equity-
Common stock, $.10 par value, authorized 375,000,000 shares-
304,835,407 and 319,205,517 shares outstanding, respectively 30 32
Other paid-in capital 5,564 6,466
Accumulated other comprehensive loss (213 ) (259 )
Retained earnings 3,387 2,806
Unallocated employee stock ownership plan common stock-
521,818 shares - (10 )
Total common stockholders' equity 8,768 9,035
Long-term debt and other long-term obligations 8,617 8,535
17,385 17,570
NONCURRENT LIABILITIES:

Accumulated deferred income taxes 2,317 2,740
Asset retirement obligations 1,247 1,190
Deferred gain on sale and leaseback transaction 1,069 -
Power purchase contract loss liability 872 1,182
Retirement benefits 918 944
Lease market valuation liability 684 767
Other 1,783 1,548
8,890 8,371
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)

$ 31,653 $ 31,196

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
balance sheets.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended

September 30,

2007

2006

(In millions)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 1,041 $ 979
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 477 445
Amortization of regulatory assets 785 665
Deferral of new regulatory assets (399 ) (379 )
Nuclear fuel and lease amortization 75 67
Deferred purchased power and other costs (265 ) (323 )
Deferred income taxes and investment tax credits, net (158 ) 36
Investment impairment 16 13
Deferred rents and lease market valuation liability (41 ) (54 )
Accrued compensation and retirement benefits (50 ) 78
Commodity derivative transactions, net 5 28
Gain on asset sales (35 ) (38 )
Income from discontinued operations - 4
Cash collateral (50 ) (98 )
Pension trust contribution (300 ) -
Decrease (increase) in operating assets-
Receivables (329 ) (7 )
Materials and supplies 62 (30 )
Prepayments and other current assets (39 ) (49 )
Increase (decrease) in operating liabilities-
Accounts payable (15 ) (93 )
Accrued taxes 355 (32 )
Accrued interest 104 104
Electric service prepayment programs (52 ) (45 )
Other (36 ) (28 )
Net cash provided from operating activities 1,151 1,243

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt 1,100 1,235
Short-term borrowings, net - 482
Redemptions and Repayments-
Common stock (918 ) (600 )
Preferred stock - (107 )
Long-term debt (647 ) (993 )
Short-term borrowings, net (535 ) -
Net controlled disbursement activity 6 (22 )
Stock-based compensation tax benefit 16 -
Common stock dividend payments (464 ) (439 )
Net cash used for financing activities (1,442 ) (444 )

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (1,127 ) (990 )
Proceeds from asset sales 37 83
Proceeds from sale and leaseback transaction 1,329 -
Sales of investment securities held in trusts 1,010 1,370
Purchases of investment securities held in trusts (1,067 ) (1,381 )
Cash investments 48 109
Other 1 (13 )
Net cash provided from (used for) investing activities 231 (822 )

Net decrease in cash and cash equivalents (60 ) (23 )
Cash and cash equivalents at beginning of period 90 64
Cash and cash equivalents at end of period $ 30 $ 41

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of FirstEnergy Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of ~~September 30, 2007~~March 31, 2008 and the related consolidated statements of income, ~~and~~ comprehensive income and cash flows for each of the three-month ~~and nine-month~~ periods ended ~~September 30, 2007~~March 31, 2008 and ~~2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.~~2007. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, ~~2006,~~2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, ~~preferred stock,~~ and of cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement ~~benefit~~ plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 9, Note 3, Note ~~2(K)~~2(G) and Note 12 to the consolidated financial statements) dated February ~~27, 2007, except as to Note 2(H) and Note 16, which are as of September 14, 2007,~~28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, ~~2006,~~2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 7, 2008

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~October 31, 2007~~

3933

~~FIRSTENERGY CORP.~~

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~EXECUTIVE SUMMARY~~

Net income in the third quarter of 2007 was $413 million, or basic earnings of $1.36 per share of common stock ($1.34 diluted), compared with net income of $454 million, or basic earnings of $1.41 per share of common stock ($1.40 diluted) in the third quarter of 2006. Net income in the first nine months of 2007 was $1.04 billion, or basic earnings of $3.39 per share of common stock ($3.35 diluted), compared with net income of $979 million, or basic earnings of $2.99 per share of common stock ($2.97 diluted) in the first nine months of 2006. The decrease in FirstEnergy’s third quarter earnings was driven primarily by higher fuel and purchased power costs and increased depreciation and amortization, partially offset by higher electric sales revenues.

Change in Basic Earnings Per Share
From Prior Year Periods

Three Months
Ended
September 30,

Nine Months
Ended
September 30,

Basic Earnings Per Share – 2006 $ 1.41 $ 2.99
Revenues 0.55 1.76
Fuel and purchased power (0.37 ) (0.99 )
Depreciation and amortization (0.11 ) (0.29 )
Deferral of new regulatory assets (0.09 ) (0.01 )
Other expenses (0.16 ) (0.36 )
Reduced common shares outstanding 0.08 0.18
Non-core asset sales/impairments – 2006 (0.01 ) 0.03
PPUC NUG Accounting Adjustment – 2006 0.02 0.02
Non-core asset sales -- 2007 0.04 0.04
Saxton decommissioning regulatory asset – 2007 - 0.05
Trust securities impairment – 2007 - (0.03 )
Basic Earnings Per Share – 2007 $ 1.36 $ 3.39

~~Regulatory Matters~~

~~Ohio~~

On August 15, 2007, the PUCO approved a stipulation that creates a green pricing option for customers of the Ohio Companies. The stipulation was filed on May 29, 2007 by the Ohio Companies, the PUCO Staff, and the OCC. The Green Resource Program will enable customers to support the development of alternative energy resources through their voluntary participation in this alternative to the Ohio Companies’ standard service offer for generation supply. The Green Resource Program will be established through the Ohio Companies’ purchase of Renewable Energy Certificates (RECs) at prices determined through a competitive bidding process monitored by the PUCO.

On August 16, 2007, the PUCO held a technical conference for interested parties to gain a better understanding of the Ohio Companies’ competitive generation supply plan proposal filed with the PUCO on July 10, 2007. The proposal seeks approval to conduct a competitive bidding process to provide generation service, beginning January 1, 2009, to customers who choose not to purchase electricity from an alternative supplier. The proposal is currently pending before the PUCO.

On August 29, 2007, the Supreme Court of Ohio upheld findings by the PUCO approving several provisions of the Ohio Companies’ RCP. The Court, however, remanded the portion of the order that authorized the Ohio Companies to collect deferred fuel costs through future distribution rates back to the PUCO for further consideration. The Court found recovery of competitive generation service costs through noncompetitive distribution rates unlawful. The PUCO’s order had authorized the Ohio Companies to defer increased fuel costs incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances, and to recover these deferred costs over a 25-year period beginning in 2009. On September 7, 2007, the Ohio Companies filed a Motion for Reconsideration with the Court on the issue of the deferred fuel costs. On September 10, 2007, the Ohio Companies filed an Application on remand with the PUCO proposing that the increased fuel costs be recovered through two generation-related fuel cost recovery riders during the period of October 2007 through December 2008, subject to reconciliation which is expected to continue through the first quarter of 2009. This matter is currently pending before the PUCO. Although unable to predict the ultimate outcome of this matter, the Ohio Companies intend to continue deferring the fuel costs pursuant to the RCP, pending the Court’s disposition of the Motion for Reconsideration and the PUCO’s action with respect Ohio Companies’ Application.

On September 25, 2007, the Ohio Governor’s proposed energy plan was officially introduced into the Ohio Senate. The bill proposes to revise state energy policy to address electric generation pricing after 2008, establish advanced energy portfolio standards and energy efficiency standards, and create GHG emission reporting and carbon control planning requirements. The bill also proposes to move to a “hybrid” system for determining rates for PLR service in which electric utilities would provide regulated generation service unless they satisfy a statutory burden to demonstrate the existence of a competitive market for retail electricity. The Senate Energy & Public Utilities Committee which has been conducting hearings on the bill and receiving testimony from interested parties, including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer groups, utility executives and others. On October 4, 2007, FirstEnergy’s Chief Executive Officer provided testimony to the Committee citing several concerns with the current version of the bill, including its lack of context in which to establish prices. He recommended that the PUCO be provided the clear statutory authority to negotiate rate plans, and in the event that negotiations do not result in rate plan agreements, a competitive bidding process be utilized to establish generation prices for customers that do not choose alternative suppliers. He also proposed that the PUCO’s statutory authority be expanded to promote societal programs such as energy efficiency, demand response, renewable power, and infrastructure improvements. Several proposed amendments to the bill have been submitted, including those from Ohio’s investor-owned electric utilities. A substitute version of the bill, which incorporated certain of the proposed amendments, was introduced into the Senate Energy & Public Utilities Committee on October 25, 2007.

~~Pennsylvania~~

On September 21 and October 5, 2007, responsive and reply briefs, respectively, were filed by the parties in the appeal of the PPUC’s January 2007 transition rate plan order to the Pennsylvania Commonwealth Court. Met-Ed and Penelec have appealed the PPUC’s decision on the denial of generation rate relief and on a consolidated income tax adjustment related to the cost of capital, while other parties appealed the PPUC’s decision on transmission rate relief. Oral arguments are expected to take place in late 2007 or early 2008.

On September 28, 2007, a Joint Petition for Settlement was filed with the PPUC for approval of Penn’s Interim Default Service Supply Plan for the three-year period covering June 1, 2008, through May 31, 2011. For customers who choose not to shop, the plan provides for Penn to obtain market-based generation supply through an RFP by rate class for residential and commercial customers, with industrial customers being supplied through short-term markets. The settlement agreement resolves all issues in the proceeding, except those regarding incremental uncollectible accounts expense, and is either supported, or not opposed, by all parties. A PPUC hearing was held on September 11, 2007 on the uncollectible expense issue. An ALJ recommended decision is expected shortly with a PPUC Order expected in late November or early December.

~~Generation~~

~~Perry~~

On August 21, 2007, FENOC announced plans to expand used nuclear fuel storage capacity at the Perry Nuclear Power Plant. The plan calls for installing above-ground, airtight steel and concrete cylindrical canisters, cooled by natural air circulation, to store used fuel assemblies. Initially, six canisters will be installed, with the capability to add up to 74 additional canisters as needed. Construction of the new fuel storage system, which is expected to cost approximately $30 million, is scheduled to begin in the spring of 2008, with completion planned for 2010.

~~Beaver Valley~~

On October 24, 2007, Beaver Valley Unit 1 returned to service following completion of its scheduled refueling outage that began on September 24, 2007. During the outage several improvement projects were completed, including reinforcing welds on the pressurizer, spray lines and safety relief valves, increasing the size of the containment sump strainer, and replacing a reactor coolant pump motor. The ten-year in-service inspection of the reactor vessel was also completed with no significant issues identified. Beaver Valley Unit 1 operated for 378 consecutive days when it was taken off line for the outage. In late August 2007, FENOC filed applications with the NRC seeking renewal of the operating licenses for Beaver Valley Units 1 and 2 for an additional 20 years, which would extend the operating licenses to January 29, 2036 for Unit 1 and May 27, 2047 for Unit 2.

~~Financial Matters~~

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended
	March 31,
	2008			2007
	(In millions except,
	per share amounts)
REVENUES:
Electric utilities	$	2,913		$	2,659
Unregulated businesses		364			314
Total revenues*		3,277			2,973

EXPENSES:
Fuel and purchased power		1,328			1,121
Other operating expenses		800			749
Provision for depreciation		164			156
Amortization of regulatory assets		258			251
Deferral of new regulatory assets		(105	)		(144	)
General taxes		215			203
Total expenses		2,660			2,336

OPERATING INCOME		617			637

OTHER INCOME (EXPENSE):
Investment income		17			33
Interest expense		(179	)		(185	)
Capitalized interest		8			5
Total other expense		(154	)		(147	)

INCOME BEFORE INCOME TAXES		463			490

INCOME TAXES		187			200

NET INCOME	$	276		$	290


BASIC EARNINGS PER SHARE OF COMMON STOCK	$	0.91		$	0.92

WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		304			314

DILUTED EARNINGS PER SHARE OF COMMON STOCK	$	0.90		$	0.92

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		307			316

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.55		$	0.50


* Includes $114 million and $108 million of excise tax collections in the first quarter of 2008 and 2007, respectively.

The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral
part of these statements.

On July 13, 2007, FGCO completed a $1.3 billion sale and leaseback transaction for its 779 MW interest in Unit 1 of the Bruce Mansfield Plant. The terms of the agreement provide for an approximate 33-year lease of the unit. FirstEnergy used the net, after-tax proceeds of approximately $1.2 billion to repay short-term debt that was used to fund its recent $900 million share repurchase program and $300 million pension contribution. FES’ registration obligations under the registration rights agreement applicable to the transaction were satisfied in September 2007, at which time the transaction was classified as an operating lease under GAAP for FES and FirstEnergy. The $1.1 billion book gain from the transaction was deferred and will be amortized ratably over the lease term. FGCO continues to operate the plant under the terms of the agreement.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)


	Three Months Ended
	March 31,
	2008			2007

	(In millions)

NET INCOME	$	276		$	290

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(20	)		(11	)
Unrealized gain (loss) on derivative hedges		(13	)		21
Change in unrealized gain on available-for-sale securities		(58	)		17
Other comprehensive income (loss)		(91	)		27
Income tax expense (benefit) related to other comprehensive income		(33	)		9
Other comprehensive income (loss), net of tax		(58	)		18

COMPREHENSIVE INCOME	$	218		$	308


The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral
part of these statements.

On August 30, 2007, Penelec issued $300 million of 6.05% unsecured senior notes due 2017. A portion of the net proceeds from the issuance and sale of the senior notes was used to fund the repurchase of $200 million of Penelec’s common stock from FirstEnergy. The remainder was used to repay short-term borrowings and for general corporate purposes.

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2008			2007
	(In millions)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	70		$	129
Receivables-
Customers (less accumulated provisions of $34 million and
$36 million, respectively, for uncollectible accounts)		1,264			1,256
Other (less accumulated provisions of $24 million and
$22 million, respectively, for uncollectible accounts)		159			165
Materials and supplies, at average cost		570			521
Prepayments and other		307			159
		2,370			2,230
PROPERTY, PLANT AND EQUIPMENT:
In service		24,894			24,619
Less - Accumulated provision for depreciation		10,454			10,348
		14,440			14,271
Construction work in progress		1,465			1,112
		15,905			15,383
INVESTMENTS:
Nuclear plant decommissioning trusts		2,025			2,127
Investments in lease obligation bonds		679			717
Other		714			754
		3,418			3,598
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,606			5,607
Regulatory assets		3,797			3,945
Pension assets		723			700
Other		596			605
		10,722			10,857
	$	32,415		$	32,068
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	2,183		$	2,014
Short-term borrowings		1,649			903
Accounts payable		754			777
Accrued taxes		416			408
Other		1,167			1,046
		6,169			5,148
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $.10 par value, authorized 375,000,000 shares-
304,835,407 shares outstanding.		31			31
Other paid-in capital		5,472			5,509
Accumulated other comprehensive loss		(108	)		(50	)
Retained earnings		3,596			3,487
Total common stockholders' equity		8,991			8,977
Long-term debt and other long-term obligations		8,332			8,869
		17,323			17,846
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,717			2,671
Asset retirement obligations		1,287			1,267
Deferred gain on sale and leaseback transaction		1,052			1,060
Power purchase contract loss liability		682			750
Retirement benefits		911			894
Lease market valuation liability		643			663
Other		1,631			1,769
		8,923			9,074
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
	$	32,415		$	32,068

The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
balance sheets.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2008			2007
	(In millions)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	276		$	290
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		164			156
Amortization of regulatory assets		258			251
Deferral of new regulatory assets		(105	)		(144	)
Nuclear fuel and lease amortization		26			26
Deferred purchased power and other costs		(59	)		(116	)
Deferred income taxes and investment tax credits, net		89			53
Investment impairment		16			5
Deferred rents and lease market valuation liability		4			(25	)
Accrued compensation and retirement benefits		(142	)		(65	)
Commodity derivative transactions, net		8			1
Gain on asset sales		(37	)		-
Cash collateral received		8			6
Pension trust contribution		-			(300	)
Decrease (increase) in operating assets-
Receivables		(6	)		(155	)
Materials and supplies		(17	)		15
Prepayments and other current assets		(115	)		(74	)
Increase (decrease) in operating liabilities-
Accounts payable		(23	)		(108	)
Accrued taxes		(5	)		73
Accrued interest		91			86
Electric service prepayment programs		(19	)		(17	)
Other		(56	)		(15	)
Net cash provided from (used for) operating activities		356			(57	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			250
Short-term borrowings, net		746			1,139
Redemptions and Repayments-
Common stock		-			(891	)
Long-term debt		(368	)		(13	)
Net controlled disbursement activity		6			12
Stock-based compensation tax benefit		11			8
Common stock dividend payments		(168	)		(159	)
Net cash provided from financing activities		227			346

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(711	)		(296	)
Proceeds from asset sales		50			-
Sales of investment securities held in trusts		361			273
Purchases of investment securities held in trusts		(384	)		(294	)
Cash investments		58			25
Other		(16	)		2
Net cash used for investing activities		(642	)		(290	)

Net decrease in cash and cash equivalents		(59	)		(1	)
Cash and cash equivalents at beginning of period		129			90
Cash and cash equivalents at end of period	$	70		$	89


The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

On October 4, 2007, FGCO and NGC closed on the issuance of $427 million of pollution control revenue bonds (PCRBs). Proceeds from the issuance will be used to redeem, during the fourth quarter of 2007, an equal amount of outstanding PCRBs originally issued on behalf of the Ohio Companies. This transaction brings the total amount of PCRBs transferred from the Ohio Companies and Penn to FGCO and NGC to approximately $1.9 billion, with approximately $265 million remaining to be transferred. The transfer of these PCRBs supports the intra-system generation asset transfer that was completed in 2005.

~~FIRSTENERGY’S BUSINESS~~

~~FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through three core business segments (see Results of Operations).~~FIRSTENERGY SOLUTIONS CORP.

· MANAGEMENT’S NARRATIVE

~~Energy Delivery Services~~ transmits and distributes electricity through FirstEnergy's eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR requirements in Pennsylvania and New Jersey. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to non-shopping retail customers under the PLR obligations in its Pennsylvania and New Jersey franchise areas. Its net income reflects the commodity costs of securing electricity from the competitive energy services segment under partial requirements purchased power agreements with FES and non-affiliated power suppliers, including associated transmission costs.

ANALYSIS OF RESULTS OF OPERATIONS

~~Competitive Energy Services~~ supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the PLR requirements of FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns or leases and operates FirstEnergy's generating facilities and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated company power sales and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.

FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services primarily in Ohio, Pennsylvania, Michigan and Maryland, and through its subsidiaries, FGCO and NGC, owns or leases and operates FirstEnergy’s fossil and hydroelectric generation facilities and owns FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.

~~Ohio Transitional Generation Services~~ supplies the electric power needs of non-shopping customers under the PLR requirements of FirstEnergy's Ohio Companies. The segment's net income is primarily derived from electric generation sales revenues less the cost of power purchased from the competitive energy services segmentFES’ revenues are primarily from the sale of electricity (provided from FES’ generating facilities and through ~~a full-requirements PSA arrangement with FES, including net transmission and ancillary costs charged by MISO to deliver energy to retail customers.~~

~~RESULTS OF OPERATIONS~~

The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 14 to the consolidated financial statements. Net income by major business segment was as follows:

Three Months Ended September 30,

Nine Months Ended September 30,

Increase

Increase

2007

2006

(Decrease)

2007

2006

(Decrease)

(In millions, except per share amounts)

Net Income (Loss)

By Business Segment:

Energy delivery services $ 269 $ 280 $ (11 ) $ 695 $ 702 $ (7 )
Competitive energy services 148 169 (21 ) 388 302 86
Ohio transitional generation services 16 27 (11 ) 69 88 (19 )
Other and reconciling adjustments* (20 ) (22 ) 2 (111 ) (113 ) 2
Total $ 413 $ 454 $ (41 ) $ 1,041 $ 979 $ 62

Basic Earnings Per Share:

Income from continuing operations $ 1.36 $ 1.40 $ (0.04 ) $ 3.39 $ 3.00 $ 0.39
Discontinued operations - 0.01 (0.01 ) - (0.01 ) 0.01
Net earnings per basic share $ 1.36 $ 1.41 $ (0.05 ) $ 3.39 $ 2.99 $ 0.40

Diluted Earnings Per Share:

Income from continuing operations $ 1.34 $ 1.39 $ (0.05 ) $ 3.35 $ 2.98 $ 0.37
Discontinued operations - 0.01 (0.01 ) - (0.01 ) 0.01
Net earnings per diluted share $ 1.34 $ 1.40 $ (0.06 ) $ 3.35 $ 2.97 $ 0.38

* Represents other operating segments and reconciling adjustments including interest expense on holding company debt and corporate support services revenues and expenses.

~~Summary of Results of Operations – Third Quarter of 2007 Compared with the Third Quarter of 2006~~

~~Financial results for FirstEnergy's major business segments in the third quarter of 2007 and 2006 were as follows:~~

Ohio

Energy

Competitive

Transitional

Other and

Delivery

Energy

Generation

Reconciling

FirstEnergy

Third Quarter 2007 Financial Results

Services

Services

Services

Adjustments

Consolidated

(In millions)

Revenues:
External
Electric $ 2,340 $ 338 $ 716 $ - $ 3,394
Other 180 32 7 28 247
Internal - 806 - (806 ) -
Total Revenues 2,520 1,176 723 (778 ) 3,641

Expenses:
Fuel and purchased power 1,116 554 631 (806 ) 1,495
Other operating expenses 436 264 80 (24 ) 756
Provision for depreciation 102 51 - 9 162
Amortization of regulatory assets 279 - 9 - 288
Deferral of new regulatory assets (82 ) - (25 ) - (107 )
General taxes 166 26 1 4 197
Total Expenses 2,017 895 696 (817 ) 2,791

Operating Income 503 281 27 39 850
Other Income (Expense):
Investment income 58 5 - (33 ) 30
Interest expense (120 ) (44 ) - (39 ) (203 )
Capitalized interest 3 5 - 1 9
Total Other Expense (59 ) (34 ) - (71 ) (164 )

Income From Continuing Operations
Before Income Taxes 444 247 27 (32 ) 686
Income taxes 175 99 11 (12 ) 273
Net Income $ 269 $ 148 $ 16 $ (20 ) $ 413

Ohio

Energy

Competitive

Transitional

Other and

Delivery

Energy

Generation

Reconciling

FirstEnergy

Third Quarter 2006 Financial Results

Services

Services

Services

Adjustments

Consolidated

(In millions)

Revenues:
External
Electric $ 2,120 $ 313 $ 682 $ - $ 3,115
Other 186 40 8 15 249
Internal - 762 - (762 ) -
Total Revenues 2,306 1,115 690 (747 ) 3,364

Expenses:
Fuel and purchased power 960 515 604 (762 ) 1,317
Other operating expenses 468 218 76 (4 ) 758
Provision for depreciation 97 49 - 7 153
Amortization of regulatory assets 237 - 6 - 243
Deferral of new regulatory assets (107 ) - (46 ) - (153 )
General taxes 157 21 5 4 187
Total Expenses 1,812 803 645 (755 ) 2,505

Operating Income 494 312 45 8 859
Other Income (Expense):
Investment income 80 18 - (52 ) 46
Interest expense (109 ) (52 ) - (24 ) (185 )
Capitalized interest 4 3 - - 7
Subsidiaries' preferred stock dividends (2 ) - - - (2 )
Total Other Expense (27 ) (31 ) - (76 ) (134 )

Income From Continuing Operations
Before Income Taxes 467 281 45 (68 ) 725
Income taxes 187 112 18 (44 ) 273
Income from continuing operations 280 169 27 (24 ) 452
Discontinued operations - - - 2 2
Net Income $ 280 $ 169 $ 27 $ (22 ) $ 454

Changes Between Third Quarter 2007 and

Third Quarter 2006 Financial Results

Increase (Decrease)

Revenues:
External
Electric $ 220 $ 25 $ 34 $ - $ 279
Other (6 ) (8 ) (1 ) 13 (2 )
Internal - 44 - (44 ) -
Total Revenues 214 61 33 (31 ) 277

Expenses:
Fuel and purchased power 156 39 27 (44 ) 178
Other operating expenses (32 ) 46 4 (20 ) (2 )
Provision for depreciation 5 2 - 2 9
Amortization of regulatory assets 42 - 3 - 45
Deferral of new regulatory assets 25 - 21 - 46
General taxes 9 5 (4 ) - 10
Total Expenses 205 92 51 (62 ) 286

Operating Income 9 (31 ) (18 ) 31 (9 )
Other Income (Expense):
Investment income (22 ) (13 ) - 19 (16 )
Interest expense (11 ) 8 - (15 ) (18 )
Capitalized interest (1 ) 2 - 1 2
Subsidiaries' preferred stock dividends 2 - - - 2
Total Other Expense (32 ) (3 ) - 5 (30 )

Income From Continuing Operations
Before Income Taxes (23 ) (34 ) (18 ) 36 (39 )
Income taxes (12 ) (13 ) (7 ) 32 -
Income from continuing operations (11 ) (21 ) (11 ) 4 (39 )
Discontinued operations - - - (2 ) (2 )
Net Income $ (11 ) $ (21 ) $ (11 ) $ 2 $ (41 )

~~Energy Delivery Services – Third Quarter 2007 Compared to Third Quarter 2006~~

~~Net income decreased $11 million (or 4%) to $269 million in the third quarter of 2007 compared to $280 million in the third quarter of 2006, primarily due to increased~~ purchased power ~~costs~~arrangements) to affiliated utility companies to meet all or a portion of their PLR requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and ~~higher amortization~~TE to supply each of ~~regulatory assets, partially offset by higher revenues and reduced other operating expenses.~~

~~Revenues –~~

~~The increase in total revenues resulted from the following sources:~~

Three Months Ended

September 30,

Revenues by Type of Service

2007

2006

Increase
(Decrease)

(In millions)

Distribution services

$
1,104

$
1,124

$
(20
)
Generation sales:

Retail

942

857

85

Wholesale

207

91

116

Total generation sales

1,149

948

201

Transmission

219

177

42

Other

48

57

(9
)
Total Revenues

$
2,520

$
2,306

$
214

~~The change in distribution KWH deliveries by customer class are summarized in the following table:~~

~~Electric Distribution KWH Deliveries~~
~~Residential~~	~~(1.7)~~	%
~~Commercial~~	~~1.4~~	%
~~Industrial~~	~~1.0~~	%
~~Total Distribution KWH Deliveries~~	~~(0.5)~~	%

~~The reduction in distribution services revenues was primarily due to distribution rate decreases for~~their PLR obligations through 2008, at prices that take into consideration their respective PUCO-authorized billing rates. FES also has a partial requirements wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to supply a portion of each of their respective PLR obligations at fixed prices through 2010. The fixed prices under the partial requirements agreement are expected to remain below wholesale market prices during the term of the agreement. FES also supplies the majority of the PLR requirements of Penn at market-based rates as a result of a ~~January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).~~competitive solicitation conducted by Penn. FES’ existing contractual obligations to Penn expire on May 31, 2008, but could continue if FES successfully bids in future competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, Maryland and Michigan.

~~The following table summarizes the price and volume factors contributing to the $201 million increase in generation revenues in the third quarter~~Results of ~~2007 compared to 2006:~~

Sources of Change in Generation Revenues

Increase
(Decrease)

(In millions)

Retail:
  Effect of 5.9% decrease in sales volumes $ (50 )
  Change in prices

135

85

Wholesale:
  Effect of 95% increase in sales volumes 86
  Change in prices

30

116

Net Increase in Generation Sales $ 201

The increase in retail generation prices during the third quarter of 2007 compared to 2006 was primarily due to increased generation rates for JCP&L resulting from the New Jersey BGS auction and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market beginning in January 2007.

Transmission revenues increased $42 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred, with no material effect to current period earnings (see Outlook – State Regulatory Matters – Pennsylvania).

Operations

~~Expenses –~~

~~The~~In the first three months of 2008, net ~~increases in revenues discussed above were offset by a $205~~income decreased to $90 million ~~increase in expenses due to the following:~~

Purchased power costs were $157 million higher in the third quarter of 2007 due to higher unit costs, increased volumes purchased and a decrease in purchased power cost deferrals. The increased unit costs reflected the effect of higher JCP&L purchased power unit prices resulting from the BGS auction. The increased KWH purchases in 2007 primarily resulted from more sales to the PJM wholesale market by Met-Ed and Penelec. Deferred purchased power costs were lower due to higher generation charges to JCP&L customers. The following table summarizes the sources of changes in purchased power costs:

Sources of Change in Purchased Power

Increase

(In millions)

Purchased Power:
   Change due to increased unit costs $ 97
   Change due to increased volume 42
   Decrease in NUG costs deferred 18
      Net Increase in Purchased Power Costs $ 157

~~Amortization of regulatory assets increased $42 million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC revenues for JCP&L as discussed above.~~

The deferral of new regulatory assets during the third quarter of 2007 was $25 million lower than in 2006 due in part to $40 million in reduced deferrals of transmission related PJM costs. The reduced deferral in the third quarter of 2007 was attributable to greater recovery of PJM costs in the 2007 period under the transmission service charge rider (see Outlook – State Regulatory Matters - Pennsylvania). The reduction in deferred PJM costs was partially offset by higher distribution deferrals under the RCP.

· ~~Other operating expenses decreased $32 million, partially offsetting the above increases, due to the net effects of:~~

-	~~A decrease of $21 million in transmission expenses caused by the expiration of transmission hedging instruments and reduced financial transmission rights revenue.~~

-~~A decrease in operation and maintenance expenses of $19 million primarily due to lower employee labor and benefit costs ($10 million) lower uncollectible~~

~~expenses related to customer receivables ($4 million) and lower leased equipment costs ($3 million).~~

- ~~An increase in miscellaneous operating expenses ($9 million) resulting~~ from ~~increased corporate support billings from FESC.~~

~~Other Expense –~~

Other expense increased $32 million in 2007 compared to the third quarter of 2006 primarily due to lower investment income of $22 million resulting from the repayment of notes receivable from affiliates since the third quarter of 2006, and increased interest expense of $11 million related in part to new debt issuances by CEI, JCP&L and Penelec.

~~Competitive Energy Services – Third Quarter 2007 Compared to Third Quarter 2006~~

~~Net income for this segment was $148 million in the third quarter of 2007 compared to $169~~$103 million in the same period ~~last year. Increased~~in 2007. The decrease in net income was primarily due to higher fuel ~~and purchased power costs~~ and other operating expenses, partially offset by lower purchased power costs and higher ~~revenues, led to the $21 million decrease.~~revenues.

Revenues

Revenues –

~~Total revenues~~ increased ~~$61~~by $81 million in the ~~third quarter~~first three months of ~~2007~~2008 compared to the same period in ~~2006. This increase primarily resulted~~2007 due to increases in revenues from ~~increased~~non-affiliated and affiliated wholesale sales, ~~to the Ohio Companies, Met-Ed and Penelec as well as higher unit prices from the Ohio Companies. These increases were~~ partially offset by lower retail generation sales. Retail generation sales ~~to Penn~~revenues decreased as a result of decreased sales in the ~~implementation of its competitive solicitation process~~PJM market partially offset by increased sales in ~~2007. Higher retail revenues resulted from increased KWH~~the MISO market. Lower sales in the PJM market were primarily due to lower contract renewals for commercial and industrial customers. Greater sales in the MISO market were primarily due to FES’ capturing more shopping customers in Penn’s service territory, partially offset by ~~reduced volume in the PJM market.~~

~~Increased non-affiliated~~lower customer usage. Non-affiliated wholesale revenues ~~primarily reflected capacity revenues earned in PJM’s new capacity market. The capacity market was initiated in June 2007 to encourage the development~~increased as a result of ~~capacity resources in PJM. Lower~~more generation available for wholesale sales to ~~non-affiliates partially offset these increases due to decreased generation available for the non-affiliated wholesale market.~~

~~The increase in reported segment revenues resulted from the following sources:~~

Three Months Ended

September 30,

Increase

Revenues By Type of Service

2007

2006

(Decrease)

(In millions)

Non-Affiliated Generation Sales:

Retail

$
189

$
178

$
11

Wholesale

149

134

15

Total Non-Affiliated Generation Sales

338

312

26

Affiliated Generation Sales

806

762

44

Transmission

26

32

(6
)
Other

6

9

(3
)
Total Revenues

$
1,176

$
1,115

$
61

~~The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:~~

Increase

Source of Change in Non-Affiliated Generation Sales

(Decrease)

(In millions)

Retail:
Effect of 0.2% increase in sales volumes
$ 1
Change in prices

10

11

Wholesale:
Effect of 11% decrease in sales volumes
(15 )
Change in prices

30

15

Net Increase in Non-Affiliated Generation Sales
$
26

Source of Change in Affiliated Generation Sales

Increase

(In millions)

Ohio Companies:
Effect of 2% increase in sales volumes
$ 12
Change in prices

14

26

Pennsylvania Companies:
Effect of 8% increase in sales volumes
13
Change in prices

5

18

Net Increase in Affiliated Generation Sales
$
44

~~Expenses -~~

~~Total expenses were $92 million higher in the third quarter of 2007 due to the net effect of the following factors:~~

Purchased power costs increased $55 million due primarily to higher volumes for replacement power related to a forced outage at Perry in the third quarter of 2007 and higher market prices. The sources of change in purchased power costs are summarized in the following table:

Source of Change in Purchased Power

Increase

(In millions)

Change due to increased unit costs
$ 14
Change due to 18% increase in volume
31
Change due to new PJM capacity market 10
Total Increase in Purchased Power Costs $ 55

Fuel costs were $16 million lower primarily due to lower coal prices ($8 million), reduced emission allowance costs ($5 million) and a decrease in natural gas consumed resulting from reduced combustion turbine generation ($2 million).

~~Fossil operating costs were $32 million higher in 2007 primarily due to the absence of gains on the sales of emissions allowances recognized in 2006.~~

~~Miscellaneous operating expenses were $13 million higher primarily due to increased contractor expenses related to the Beaver Valley Unit 1 outage and corporate support billings from FESC.~~

~~Higher general taxes of $5 million resulted from increased gross receipts taxes and property taxes.~~

~~Ohio Transitional Generation Services – Third Quarter 2007 Compared to Third Quarter 2006~~

Net income decreased $11 million to $16 million in the third quarter of 2007 compared to $27 million in the same period last year. Higher purchased power costs were partially offset by higher generation revenues.

~~Revenues –~~non-affiliates.

The increase in ~~reported segment revenues resulted from the following sources:~~

Three Months Ended

September 30,

Revenues by Type of Service

2007

2006

Increase

(In millions)

Generation sales:

Retail

$
622

$
605

$
17

Wholesale

3

3

-

Total generation sales

625

608

17

Transmission

98

82

16

Total Revenues

$
723

$
690

$
33

~~The following table summarizes the price and volume factors contributing to the increase in generation~~affiliated company wholesale sales ~~revenues from retail customers:~~

Source of Change in Generation Sales

Increase

(In millions)

Effect of 2% increase in sales volumes
$ 10
Change in prices

7

Total Increase in Retail Generation Sales
$
17

The increase in generation sales was primarily due to higher weather-related usage in the third quarter of 2007 resulting from slightly higher than normal cooling degree days during the period. Average prices increased slightly due to customer usage patterns and higher composite unit prices for returning customers.

~~Expenses -~~

~~Purchased power costs were $27 million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:~~

Source of Change in Purchased Power

Increase

(In millions)

Purchases from non-affiliates:
Change due to increased unit costs
$ -
Change due to volume
1
1
Purchases from FES:
Change due to increased unit costs
14
Change due to volume
12
26
Total Increase in Purchased Power Costs $ 27

~~The increase in volumes purchased~~ was due to the higher retail generation sales requirements. The higher unit costs resulted from the provision of the full-requirements PSA with FES under which purchased power unit costs reflected the increases in the Ohio Companies’ retail generation sales unit prices.

~~The deferral of new regulatory assets decreased by $21 million in the third quarter of 2007 compared to 2006 due to reduced cost deferrals under the Ohio Companies’ RCP.~~

~~Other – Third Quarter 2007 Compared to Third Quarter 2006~~

~~Summary of Results of Operations – First Nine Months of 2007 Compared with the First Nine Months of 2006~~

~~Financial results for FirstEnergy's major business segments in the first nine months of 2007 and 2006 were as follows:~~

Ohio

Energy

Competitive

Transitional

Other and

Delivery

Energy

Generation

Reconciling

FirstEnergy

First Nine Months 2007 Financial Results

Services

Services

Services

Adjustments

Consolidated

(In millions)

Revenues:
External
Electric $ 6,148 $ 973 $ 1,942 $ - $ 9,063
Other 507 116 26 11 660
Internal - 2,210 - (2,210 ) -
Total Revenues 6,655 3,299 1,968 (2,199 ) 9,723

Expenses:
Fuel and purchased power 2,838 1,461 1,712 (2,210 ) 3,801
Other operating expenses 1,255 839 218 (57 ) 2,255
Provision for depreciation 301 153 - 23 477
Amortization of regulatory assets 765 - 20 - 785
Deferral of new regulatory assets (299 ) - (100 ) - (399 )
General taxes 486 81 3 19 589
Total Expenses 5,346 2,534 1,853 (2,225 ) 7,508

Operating Income 1,309 765 115 26 2,215
Other Income (Expense):
Investment income 190 13 1 (111 ) 93
Interest expense (347 ) (144 ) (1 ) (101 ) (593 )
Capitalized interest 7 13 - 1 21
Total Other Expense (150 ) (118 ) - (211 ) (479 )

Income From Continuing Operations
Before Income Taxes 1,159 647 115 (185 ) 1,736
Income taxes 464 259 46 (74 ) 695
Net Income $ 695 $ 388 $ 69 $ (111 ) $ 1,041

Ohio

Energy

Competitive

Transitional

Other and

Delivery

Energy

Generation

Reconciling

FirstEnergy

First Nine Months 2006 Financial Results

Services

Services

Services

Adjustments

Consolidated

(In millions)

Revenues:
External
Electric $ 5,434 $ 955 $ 1,790 $ - $ 8,179
Other 442 122 18 60 642
Internal 14 1,997 - (2,011 ) -
Total Revenues 5,890 3,074 1,808 (1,951 ) 8,821

Expenses:
Fuel and purchased power 2,343 1,416 1,558 (2,011 ) 3,306
Other operating expenses 1,197 838 185 10 2,230
Provision for depreciation 282 143 - 20 445
Amortization of regulatory assets 650 - 15 - 665
Deferral of new regulatory assets (275 ) - (104 ) - (379 )
General taxes 459 70 7 17 553
Total Expenses 4,656 2,467 1,661 (1,964 ) 6,820

Operating Income 1,234 607 147 13 2,001
Other Income (Expense):
Investment income 244 35 - (159 ) 120
Interest expense (310 ) (148 ) (1 ) (69 ) (528 )
Capitalized interest 11 9 - 1 21
Subsidiaries' preferred stock dividends (9 ) - - 3 (6 )
Total Other Expense (64 ) (104 ) (1 ) (224 ) (393 )

Income From Continuing Operations
Before Income Taxes 1,170 503 146 (211 ) 1,608
Income taxes 468 201 58 (102 ) 625
Income from continuing operations 702 302 88 (109 ) 983
Discontinued operations - - - (4 ) (4 )
Net Income $ 702 $ 302 $ 88 $ (113 ) $ 979

Changes Between First Nine Months 2007

and First Nine Months 2006

Financial Results Increase (Decrease)

Revenues:
External
Electric $ 714 $ 18 $ 152 $ - $ 884
Other 65 (6 ) 8 (49 ) 18
Internal (14 ) 213 - (199 ) -
Total Revenues 765 225 160 (248 ) 902

Expenses:
Fuel and purchased power 495 45 154 (199 ) 495
Other operating expenses 58 1 33 (67 ) 25
Provision for depreciation 19 10 - 3 32
Amortization of regulatory assets 115 - 5 - 120
Deferral of new regulatory assets (24 ) - 4 - (20 )
General taxes 27 11 (4 ) 2 36
Total Expenses 690 67 192 (261 ) 688

Operating Income 75 158 (32 ) 13 214
Other Income (Expense):
Investment income (54 ) (22 ) 1 48 (27 )
Interest expense (37 ) 4 - (32 ) (65 )
Capitalized interest (4 ) 4 - - -
Subsidiaries' preferred stock dividends 9 - - (3 ) 6
Total Other Expense (86 ) (14 ) 1 13 (86 )

Income From Continuing Operations
Before Income Taxes (11 ) 144 (31 ) 26 128
Income taxes (4 ) 58 (12 ) 28 70
Income from continuing operations (7 ) 86 (19 ) (2 ) 58
Discontinued operations - - - 4 4
Net Income $ (7 ) $ 86 $ (19 ) $ 2 $ 62

~~Energy Delivery Services – First Nine Months of 2007 Compared to First Nine Months of 2006~~

Net income decreased $7 million (or 1%) to $695 million in the first nine months of 2007 compared to $702 million in the first nine months of 2006, primarily due to increased revenues partially offset by higher operating expenses and other expenses.

~~Revenues –~~

~~The increase in total revenues resulted from the following sources:~~

Nine Months Ended

September 30,

Revenues by Type of Service

2007

2006

Increase

(In millions)

Distribution services

$
2,996

$
2,972

$
24

Generation sales:

Retail

2,417

2,138

279

Wholesale

489

196

293

Total generation sales

2,906

2,334

572

Transmission

595

426

169

Other

158

158

-

Total Revenues

$
6,655

$
5,890

$
765

~~The change in distribution deliveries by customer class is summarized in the following table:~~

~~Electric Distribution KWH Deliveries~~
~~Residential~~	~~4.4~~	%
~~Commercial~~	~~3.4~~	%
~~Industrial~~	~~(0.4~~	)%
~~Total Distribution KWH Deliveries~~	~~2.5~~	%

The increase in electric distribution deliveries to customers was primarily due to higher weather-related usage during the first nine months of 2007 compared to the same period of 2006 (heating degree days increased by 13.7% and cooling degree days increased by 9.5%). The higher revenues from increased distribution deliveries were partially offset by distribution rate decreases for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).

~~The following table summarizes the price and volume factors contributing to the $572 million increase in non-affiliated generation sales revenues in 2007 compared to 2006:~~

Sources of Change in Generation Sales

Increase
(Decrease)

(In millions)

Retail:
  Effect of 2% decrease in sales volumes $ (38 )
  Change in prices
317

279

Wholesale:
  Effect of 118% increase in sales volumes 232
  Change in prices
61

293

Net Increase in Generation Sales $ 572

The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in Penn’s service territory in the first nine months of 2007. The increase in retail generation prices during the first nine months of 2007 compared to 2006 was primarily due to increased generation rates for JCP&L resulting from the New Jersey BGS auction process and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market beginning in January 2007.

Transmission revenues increased $169 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred, with no material effect on current period earnings (see Outlook – State Regulatory Matters – Pennsylvania).

~~Expenses –~~

~~The increases in revenues discussed above were partially offset by a $690 million increase in expenses due to the following:~~

Purchased power costs were $495 million higher in the first nine months of 2007 due to higher unit costs and volumes purchased. The increased unit costs reflected the effect of higher JCP&L costs resulting from the BGS auction process. The increased purchases in 2007 were due primarily to higher sales to the wholesale market. The following table summarizes the sources of changes in purchased power costs:

Sources of Change in Purchased Power

Increase

(In millions)

Purchased Power:
   Change due to increased unit costs $ 261
   Change due to increased volume 174
   Decrease in NUG costs deferred 60
      Net Increase in Purchased Power Costs $ 495

~~Other operating expenses increased $58 million due to the net effects of:~~

-	~~An increase of $80 million in MISO and PJM transmission expenses, resulting primarily from higher congestion costs.~~

-	~~A decrease in miscellaneous operating expenses of $10 million primarily due to changes in the assessment of regulatory fees and employee benefits~~ ~~from FESC.~~

-	~~A decrease in operation and maintenance expenses of $9 million primarily due to increased labor activities devoted to construction projects in 2007.~~

~~Amortization of regulatory assets increased $115 million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC rates for JCP&L as discussed above.~~

The deferral of new regulatory assets during the first nine months of 2007 was $24 million higher in 2007 primarily due to the deferral of previously expensed decommissioning costs of $27 million related to the Saxton nuclear research facility (see Outlook – State Regulatory Matters - Pennsylvania), increased RCP distribution deferrals of $23 million, offset by a reduction in deferred PJM transmission costs of $30 million.

·	~~Depreciation expense increased $19 million and property taxes increased $27 million due primarily to property additions since the third quarter of 2006.~~

~~Other Expense –~~

Other expense increased $86 million in 2007 compared to the first nine months of 2006 primarily due to lower investment income of $54 million resulting from the repayment of notes receivable from affiliates since the third quarter of 2006 and increased interest expense of $37 million related to new debt issuances by CEI, JCP&L and Penelec.

~~Competitive Energy Services – First Nine Months of 2007 Compared to First Nine Months of 2006~~

Net income for this segment was $388 million in the first nine months of 2007 compared to $302 million in the same period last year. This increase reflects an improvement in gross generation margin and lower nuclear production costs, which were partially offset by increased depreciation and general taxes and reduced investment income.

~~Revenues –~~

~~Total revenues increased $225 million in the first nine months of 2007 compared to the same period in 2006. This increase primarily resulted from higher unit prices under affiliated generation~~greater sales to the Ohio and Pennsylvania Companies ~~and increased retail sales, which were partially offset by lower non-affiliated wholesale sales.~~

~~The higher retail revenues resulted from increased sales in both the MISO and PJM markets. The increase in MISO retail sales primarily reflect FES’ increased sales~~ to shopping customers in Penn’s service territory. Lower non-affiliated wholesale revenues reflected the effect of decreased generation available for the non-affiliated wholesale market due to increased affiliated company power sales under the Ohio Companies’ full-requirements PSA and the partial-requirements power sales agreement with Met-Ed and Penelec.

~~The increased affiliated company generation revenues were due to higher unit prices and increased sales volumes. The increase in PSA sales to the Ohio Companies was due to~~meet their higher retail generation sales requirements. ~~The higher~~Higher unit prices resulted from the provision of the full-requirements PSA under which PSA rates reflect the ~~increases~~increase in the Ohio Companies’ retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn due to a 45% increase in customer shopping in the ~~implementation~~first quarter of ~~its competitive solicitation process in~~2008 compared to the first quarter of 2007.

~~The increase in reported segment revenues resulted from the following sources:~~

Nine Months Ended

September 30,

Increase

Revenues by Type of Service

2007

2006

(Decrease)

(In millions)

Non-Affiliated Generation Sales:

Retail

$
547

$
445

$
102

Wholesale

425

509

(84
)
Total Non-Affiliated Generation Sales

972

954

18

Affiliated Generation Sales

2,210

1,997

213

Transmission

71

96

(25
)
Other

46

27

19

Total Revenues

$
3,299

$
3,074

$
225

Transmission ~~revenues decreased $25~~revenue increased $10 million due to ~~reduced~~increased retail load in the MISO market ~~lower~~and higher transmission ~~rates and~~prices ($12 million), partially offset by reduced ~~financial transmission rights~~FTR auction ~~revenue.~~revenues ($2 million).

Changes in revenues in the first three months of 2008 from the same period of 2007 are summarized below:

	Three Months Ended
	March 31,				Increase
Revenues by Type of Service	2008		2007		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	160	$	174	$	(14	)
Wholesale		129		103		26
Total Non-Affiliated Generation Sales		289		277		12
Affiliated Generation Sales		776		714		62
Transmission		33		23		10
Other		1		4		(3	)
Total Revenues	$	1,099	$	1,018	$	81

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated generation ~~sales:~~sales in the first three months of 2008 compared to the same period last year:

Increase

Source of Change in Non-Affiliated Generation Sales

(Decrease)

(In millions)

Retail:
Effect of 12% increase in sales volumes
$ 52
Change in prices

50

102

Wholesale:
Effect of 26% decrease in sales volumes
(131 )
Change in prices

47

(84
)
Net Increase in Non-Affiliated Generation Sales
$
18

Source of Change in Affiliated Generation Sales

Increase

(In millions)

Ohio Companies:
Effect of 4% increase in sales volumes
$ 56
Change in prices

89

145

Pennsylvania Companies:
Effect of 12% increase in sales volumes
54
Change in prices

14

68

Net Increase in Affiliated Generation Sales
$
213

	Increase
Source of Change in Non-Affiliated Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 9.0% decrease in sales volumes	$	(16	)
Change in prices		2
		(14	)
Wholesale:
Effect of 3.5% increase in sales volumes		4
Change in prices		22
		26
Net Increase in Non-Affiliated Generation Revenues	$	12

	Increase
Source of Change in Affiliated Generation Revenues	(Decrease)
	(In millions)
Ohio Companies:
Effect of 1.2% increase in sales volumes	$	6
Change in prices		44
		50
Pennsylvania Companies:
Effect of 9.0% increase in sales volumes		16
Change in prices		(4	)
		12
Net Increase in Affiliated Generation Revenues	$	62

Expenses -

Total expenses increased ~~$67~~by $94 million in the first ~~nine~~three months of ~~2007 due to the following factors:~~

~~Purchased power costs increased $86 million due principally to higher volumes for replacement power related to the forced outages at Bruce Mansfield and Perry.~~

Higher fossil operating costs of $43 million due to the absence of gains from the sale of emissions allowances recognized in 2006 ($24 million) and increased scheduled maintenance outages ($13 million).

~~Higher depreciation expenses of $10 million were due to property additions.~~

~~Higher general taxes of $11 million resulted from increased gross receipts taxes and property taxes.~~

~~Partially offsetting the higher costs were:~~

Fuel costs were $41 million lower primarily due to reduced coal costs and emission allowance costs offset by increases in nuclear fuel and natural gas costs. Coal costs were reduced due to a $14 million inventory adjustment and $23 million of reduced coal consumption reflecting lower generation. Reduced emission allowance costs ($18 million) were partially offset by increased natural gas costs ($4 million) due to increased consumption and nuclear fuel costs ($8 million) due to increased consumption and higher prices.

·~~Nuclear operating costs were $54 million lower due to fewer outages in 2007~~2008 compared ~~to 2006 and reduced employee benefit costs.~~

~~Other Expense –~~

Total other expense in the first nine months of 2007 was $14 million higher than the 2006 period primarily due to decreased earnings on nuclear decommissioning trust investments (including a $16 million impairment in 2007).

~~Ohio Transitional Generation Services – First Nine Months of 2007 Compared to First Nine Months of 2006~~

~~Net income for this segment decreased to $69 million in the first nine months of 2007 from $88 million in~~with the same period ~~last year. Higher operating expenses, primarily for purchased power, were partially offset by higher generation revenues.~~

~~Revenues –~~

~~The increase in reported segment revenues resulted from the following sources:~~

Nine Months Ended

September 30,

Increase

Revenues by Type of Service

2007

2006

(Decrease)

(In millions)

Generation sales:

Retail

$
1,712

$
1,581

$
131

Wholesale

7

12

(5
)
Total generation sales

1,719

1,593

126

Transmission

248

213

35

Other

1

2

(1
)
Total Revenues

$
1,968

$
1,808

$
160

of 2007. The following table summarizes the ~~price and volume~~ factors contributing to the ~~increase~~changes in ~~sales revenues~~fuel and purchased power costs in the first three months of 2008 from ~~retail customers:~~the same period last year:

Source of Change in Generation Sales

Increase

(In millions)

Retail:
Effect of 4% increase in sales volumes
$ 66
Change in prices

65

Total Increase in Retail Generation Sales
$
131

Source of Change in Fuel and Purchased Power	Increase (Decrease)
	(In millions)
Nuclear Fuel:
Change due to increased unit costs	$	1
Change due to volume consumed		(3	)
		(2	)
Fossil Fuel:
Change due to increased unit costs		19
Change due to volume consumed		71
		90
Non-affiliated Purchased Power:
Change due to increased unit costs		55
Change due to volume purchased		(34	)
		21
Affiliated Purchased Power:
Change due to decreased unit costs		(16	)
Change due to volume purchased		(35	)
		(51	)
Net Increase in Fuel and Purchased Power Costs	$	58

Fossil fuel costs increased $90 million in the first three months of 2008 primarily as a result of increased coal consumption reflecting higher generation as a result of fewer outages in 2008 compared to 2007. Higher unit prices were due to increased coal transportation and emission allowance costs in the first quarter of 2008. The higher fossil fuel costs were partially offset by lower nuclear fuel costs of $2 million. Lower nuclear fuel costs reflect decreased nuclear generation primarily as a result of the refueling outage at Davis-Besse in the first quarter of 2008.

5539

~~The increase~~Purchased power costs decreased as a result of lower purchases from affiliates, partially offset by increased non-affiliated purchased power costs. Purchases from affiliated companies decreased as a result of the assignment of CEI’s and TE’s leasehold interests in ~~generation sales was~~the Mansfield Plant to FGCO in October 2007. Purchased power costs from non-affiliates increased primarily as a result of higher market rates partially offset by reduced volume requirements due to increased available fossil generation.

Other operating expenses increased by $33 million in the first three months of 2008 from the same period of 2007 primarily due to ~~higher weather-related usage~~lease expenses relating to the assignment of CEI’s and TE’s leasehold interests in the Mansfield Plant to FGCO and the sale and leaseback of Mansfield Unit 1 that were completed subsequent to the first quarter in 2007. Higher nuclear operating costs were due to the refueling outage at Davis-Besse and preparatory work associated with the Beaver Valley Unit 2 refueling outage that is scheduled for the second quarter of 2008.

Depreciation expense increased by $2 million in the first ~~nine~~three months of ~~2007~~2008 primarily due to fossil and nuclear property additions since the first quarter of 2007.

General taxes increased by $1 million in the first three months of 2008 compared to the same period of 2007 as a result of higher gross receipts taxes and property taxes.

Other Expense

Other expense increased by $4 million in the first three months of 2008 from the same period of 2007 primarily as a result of an increase in trust securities impairments and reduced loans to the unregulated money pool, partially offset by lower interest expense. Lower interest expense reflected the repayment of notes issued to associated companies in connection with the transfers of generation assets in 2005, partially offset by the issuance of lower-cost pollution control debt subsequent to March 31, 2007.

Legal Proceedings

See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to FES.

New Accounting Standards and Interpretations

See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to FES.

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of FirstEnergy Solutions Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its subsidiaries as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed ~~above,~~in Note 8, Note 4, Note 2(G) and ~~reduced customer shopping. Average prices~~Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 7, 2008

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,
	2008			2007
	(In thousands)


REVENUES:
Electric sales to affiliates	$	776,307		$	713,674
Electric sales to non-affiliates		301,266			287,629
Other		21,543			16,990
Total revenues		1,099,116			1,018,293

EXPENSES:
Fuel		321,689			233,535
Purchased power from non-affiliates		206,724			186,203
Purchased power from affiliates		25,485			76,483
Other operating expenses		296,546			263,596
Provision for depreciation		49,742			48,010
General taxes		23,197			21,718
Total expenses		923,383			829,545

OPERATING INCOME		175,733			188,748

OTHER INCOME (EXPENSE):
Miscellaneous income (expense)		(2,904	)		19,732
Interest expense to affiliates		(7,210	)		(29,446	)
Interest expense - other		(24,535	)		(17,358	)
Capitalized interest		6,663			3,209
Total other expense		(27,986	)		(23,863	)

INCOME BEFORE INCOME TAXES		147,747			164,885

INCOME TAXES		57,763			62,381

NET INCOME		89,984			102,504

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(1,820	)		(1,360	)
Unrealized gain on derivative hedges		5,718			17,758
Change in unrealized gain on available-for-sale securities		(51,852	)		17,450
Other comprehensive income (loss)		(47,954	)		33,848
Income tax expense (benefit) related to other comprehensive income		(17,403	)		12,333
Other comprehensive income (loss), net of tax		(30,551	)		21,515

TOTAL COMPREHENSIVE INCOME	$	59,433		$	124,019

The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an
integral part of these statements.

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,		December 31,
	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	2
Receivables-
Customers (less accumulated provisions of $6,988,000 and
$8,072,000, respectively, for uncollectible accounts)		125,116		133,846
Associated companies		317,740		376,499
Other (less accumulated provisions of $2,500,000 and $9,000,
respectively, for uncollectible accounts)		2,224		3,823
Notes receivable from associated companies		737,387		92,784
Materials and supplies, at average cost		474,625		427,015
Prepayments and other		135,734		92,340
		1,792,828		1,126,309
PROPERTY, PLANT AND EQUIPMENT:
In service		8,703,760		8,294,768
Less - Accumulated provision for depreciation		4,032,545		3,892,013
		4,671,215		4,402,755
Construction work in progress		1,058,080		761,701
		5,729,295		5,164,456
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		1,263,338		1,332,913
Long-term notes receivable from associated companies		62,900		62,900
Other		24,388		40,004
		1,350,626		1,435,817
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		256,983		276,923
Lease assignment receivable from associated companies		67,256		215,258
Goodwill		24,248		24,248
Property taxes		47,774		47,774
Pension assets		16,070		16,723
Unamortized sale and leaseback costs		85,695		70,803
Other		34,819		43,953
		532,845		695,682
	$	9,405,594	$	8,422,264
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,608,456	$	1,441,196
Short-term borrowings-
Associated companies		1,145,959		264,064
Other		700,000		300,000
Accounts payable-
Associated companies		405,668		445,264
Other		185,704		177,121
Accrued taxes		142,834		171,451
Other		248,106		237,806
		4,436,727		3,036,902
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 750 shares-
7 shares outstanding		1,161,473		1,164,922
Accumulated other comprehensive income		110,103		140,654
Retained earnings		1,188,639		1,108,655
Total common stockholder's equity		2,460,215		2,414,231
Long-term debt and other long-term obligations		77,956		533,712
		2,538,171	��	2,947,943
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		1,051,871		1,060,119
Accumulated deferred investment tax credits		59,969		61,116
Asset retirement obligations		823,686		810,114
Retirement benefits		65,348		63,136
Property taxes		48,095		48,095
Lease market valuation liability		341,881		353,210
Other		39,846		41,629
		2,430,696		2,437,419
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	9,405,594	$	8,422,264

The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an
integral part of these balance sheets.

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2008			2007
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	89,984		$	102,504
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		49,742			48,010
Nuclear fuel and lease amortization		25,426			26,437
Deferred rents and lease market valuation liability		(34,887	)		-
Deferred income taxes and investment tax credits, net		30,781			21,210
Investment impairment		14,943			4,169
Accrued compensation and retirement benefits		(11,042	)		(8,297	)
Commodity derivative transactions, net		8,086			537
Gain on asset sales		(4,964	)		-
Cash collateral, net		1,601			1,384
Pension trust contribution		-			(64,020	)
Decrease (increase) in operating assets:
Receivables		69,533			(62,940	)
Materials and supplies		(12,948	)		10,580
Prepayments and other current assets		(12,260	)		(1,440	)
Increase (decrease) in operating liabilities:
Accounts payable		(17,149	)		213,484
Accrued taxes		(28,652	)		(2,913	)
Accrued interest		(728	)		2,930
Other		(7,514	)		6,694
Net cash provided from operating activities		159,952			298,329

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Equity contribution from parent		-			700,000
Short-term borrowings, net		1,281,896			197,731
Redemptions and Repayments-
Long-term debt		(288,603	)		(745,444	)
Common stock dividend payments		(10,000	)		-
Net cash provided from financing activities		983,293			152,287

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(476,529	)		(117,506	)
Proceeds from asset sales		5,088			-
Sales of investment securities held in trusts		173,123			178,632
Purchases of investment securities held in trusts		(181,079	)		(188,076	)
Loans to associated companies, net		(644,604	)		(319,898	)
Other		(19,244	)		(3,768	)
Net cash used for investing activities		(1,143,245	)		(450,616	)

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

The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part of
these statements.

OHIO EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They provide generation services to those customers electing to retain OE and Penn as their power supplier. OE’s power supply requirements are provided by FES – an affiliated company. Penn purchases power from FES and third-party suppliers through a competitive RFP process.

Results of Operations

In the first three months of 2008, net income decreased to $44 million from $54 million in the same period of 2007. The decrease primarily resulted from higher operating costs, a decrease in the deferral of new regulatory assets and lower investment income, partially offset by higher electric sales revenues.

Revenues

Revenues increased by $27 million, or 4.3%, in the first three months of 2008 compared with the same period in 2007, primarily due to increases in retail generation revenues ($17 million) and distribution throughput revenues ($12 million).

Retail generation revenues increased primarily due to higher ~~composite unit~~average prices ~~for returning~~across all customer classes, partially offset by decreased KWH sales to commercial and industrial customers. The ~~percentage~~higher average prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see “Regulatory Matters – Ohio” within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries). Weather conditions in the first three months of 2008 compared to the same period in 2007 contributed to the higher KWH sales to residential customers (heating degree days increased 2.8% and 0.7% in OE’s and Penn’s service territories, respectively). Commercial and industrial retail generation ~~services provided by alternative suppliers~~KWH sales were lower due to ~~total~~increased customer shopping in Penn’s service territory in the first quarter of 2008 compared to the same period last year.

Changes in retail generation sales ~~delivered by~~and revenues in the ~~Ohio Companies in their service areas decreased by 6.4 percentage points~~first three months of 2008 from the same period ~~last year.~~

~~Expenses -~~

~~Purchased power costs were $153 million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costs~~in 2007 are summarized in the following ~~table:~~tables:

Retail Generation KWH Sales	Increase (Decrease)

Residential		1.0	%
Commercial		(2.5	)%
Industrial		(4.1	)%
Net Decrease in Generation Sales		(1.5	)%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	11
Commercial		1
Industrial		5
Increase in Generation Revenues	$	17

Revenues from distribution throughput increased by $12 million in the first three months of 2008 compared to the same period in 2007 due to higher average unit prices for all customer classes and higher KWH deliveries to residential and commercial customers. The higher average prices resulted from a transmission rider increase effective July 1, 2007. The higher KWH deliveries to residential and commercial customers reflected the favorable weather conditions described above.

Changes in distribution KWH deliveries and revenues in the first three months of 2008 from the same period in 2007 are summarized in the following tables.

Distribution KWH Deliveries	Increase (Decrease)

Residential	1.7	%
Commercial	1.2	%
Industrial	(0.8	)%
Net Increase in Distribution Deliveries	0.7	%

Distribution Revenues	Increase
	(In millions)
Residential	$	6
Commercial		4
Industrial		2
Increase in Distribution Revenues	$	12

Expenses

Source of Change in Purchased Power

Increase

(In millions)

Purchases from non-affiliates:
Change due to increased unit costs
$ 6
Change due to volume purchased
2
8
Purchases from FES:
Change due to increased unit costs
89
Change due to volume purchased
56
145
Total Increase in Purchased Power Costs $ 153
Total expenses increased by $15 million in the first three months of 2008 from the same period of 2007. The following table presents changes from the prior year by expense category.

Expenses – Changes	Increase (Decrease)
		(In millions)
Purchased power costs	$	(10	)
Nuclear operating costs		1
Other operating costs		6
Provision for depreciation		3
Amortization of regulatory assets		3
Deferral of new regulatory assets		11
General taxes		1
Net Increase in Expenses	$	15

Lower purchased power costs in the first three months of 2008 primarily reflected the lower retail generation KWH sales in Penn’s service territory described above, partially offset by higher unit prices as provided for under OE’s PSA with FES. The increase in other operating costs for the first three months of 2008 was primarily due to higher transmission expenses related to MISO operations. Higher depreciation expense in the first three months of 2008 reflected capital additions subsequent to the first quarter of 2007. Higher amortization of regulatory assets in the first three months of 2008 was primarily due to increased amortization of MISO transmission deferrals. The decrease in the deferral of new regulatory assets for the first three months of 2008 was primarily due to lower MISO costs deferred in excess of transmission revenues and lower RCP fuel and distribution cost deferrals.

Other Income

Other income decreased $12 million in the first three months of 2008 as compared with the same period of 2007 primarily due to reductions in interest income on notes receivable resulting from principal payments from associated companies since the first quarter of 2007.

Income Taxes

In the first quarter of 2007, OE’s income taxes included an immaterial adjustment applicable to prior periods of $7.2 million related to an inter-company federal tax allocation arrangement between FirstEnergy and its subsidiaries.

Legal Proceedings

New Accounting Standards and Interpretations

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Ohio Edison Company:

We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 8, Note 4, Note 2(G) and Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 7, 2008

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2008			2007
	(In thousands)

REVENUES:
Electric sales	$	622,271		$	594,344
Excise tax collections		30,378			31,254
Total revenues		652,649			625,598

EXPENSES:
Fuel		3,170			3,015
Purchased power		340,186			349,852
Nuclear operating costs		43,021			41,514
Other operating costs		94,135			88,486
Provision for depreciation		21,493			18,848
Amortization of regulatory assets		48,538			45,417
Deferral of new regulatory assets		(25,411	)		(36,649	)
General taxes		50,453			49,745
Total expenses		575,585			560,228

OPERATING INCOME		77,064			65,370

OTHER INCOME (EXPENSE):
Investment income		15,055			26,630
Miscellaneous income (expense)		(3,806	)		373
Interest expense		(17,641	)		(21,022	)
Capitalized interest		110			110
Total other income (expense)		(6,282	)		6,091

INCOME BEFORE INCOME TAXES		70,782			71,461

INCOME TAXES		26,873			17,426

NET INCOME		43,909			54,035

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(3,994	)		(3,423	)
Change in unrealized gain on available-for-sale securities		(7,571	)		(126	)
Other comprehensive loss		(11,565	)		(3,549	)
Income tax benefit related to other comprehensive loss		(4,262	)		(1,503	)
Other comprehensive loss, net of tax		(7,303	)		(2,046	)

TOTAL COMPREHENSIVE INCOME	$	36,606		$	51,989

The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part
of these statements.

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,		December 31,
	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	732	$	732
Receivables-
Customers (less accumulated provisions of $7,870,000 and $8,032,000,
respectively, for uncollectible accounts)		266,360		248,990
Associated companies		179,875		185,437
Other (less accumulated provisions of $5,638,000 and $5,639,000,
respectively, for uncollectible accounts)		16,474		12,395
Notes receivable from associated companies		589,790		595,859
Prepayments and other		17,785		10,341
		1,071,016		1,053,754
UTILITY PLANT:
In service		2,804,505		2,769,880
Less - Accumulated provision for depreciation		1,106,174		1,090,862
		1,698,331		1,679,018
Construction work in progress		60,617		50,061
		1,758,948		1,729,079
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		258,405		258,870
Investment in lease obligation bonds		253,747		253,894
Nuclear plant decommissioning trusts		119,948		127,252
Other		33,014		36,037
		665,114		676,053
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		709,969		737,326
Pension assets		235,933		228,518
Property taxes		65,520		65,520
Unamortized sale and leaseback costs		43,882		45,133
Other		44,640		48,075
		1,099,944		1,124,572
	$	4,595,022	$	4,583,458
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	334,656	$	333,224
Short-term borrowings-
Associated companies		50,692		50,692
Other		2,609		2,609
Accounts payable-
Associated companies		155,654		174,088
Other		19,376		19,881
Accrued taxes		93,390		89,571
Accrued interest		16,459		22,378
Other		99,532		65,163
		772,368		757,606
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 shares outstanding		1,220,368		1,220,512
Accumulated other comprehensive income		41,083		48,386
Retained earnings		351,186		307,277
Total common stockholder's equity		1,612,637		1,576,175
Long-term debt and other long-term obligations		839,107		840,591
		2,451,744		2,416,766
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		783,777		781,012
Accumulated deferred investment tax credits		15,990		16,964
Asset retirement obligations		95,009		93,571
Retirement benefits		176,597		178,343
Deferred revenues - electric service programs		36,821		46,849
Other		262,716		292,347
		1,370,910		1,409,086
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	4,595,022	$	4,583,458

The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part
of these balance sheets.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,

	2008			2007
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	43,909		$	54,035
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		21,493			18,848
Amortization of regulatory assets		48,538			45,417
Deferral of new regulatory assets		(25,411	)		(36,649	)
Amortization of lease costs		32,934			32,934
Deferred income taxes and investment tax credits, net		6,866			(3,992	)
Accrued compensation and retirement benefits		(19,482	)		(16,794	)
Pension trust contribution		-			(20,261	)
Increase in operating assets-
Receivables		(27,496	)		(102,469	)
Prepayments and other current assets		(7,451	)		(6,339	)
Increase (decrease) in operating liabilities-
Accounts payable		(18,939	)		42,095
Accrued taxes		2,991			(46,791	)
Accrued interest		(5,919	)		(6,812	)
Electric service prepayment programs		(10,028	)		(9,053	)
Other		(2,066	)		(3,283	)
Net cash provided from (used for) operating activities		39,939			(59,114	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		-			77,473
Redemptions and Repayments-
Common stock		-			(500,000	)
Long-term debt		(80	)		(72	)
Net cash used for financing activities		(80	)		(422,599	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(49,011	)		(29,888	)
Sales of investment securities held in trusts		62,344			12,951
Purchases of investment securities held in trusts		(63,797	)		(13,805	)
Loan repayments from associated companies, net		6,534			511,082
Cash investments		147			168
Other		3,924			1,187
Net cash provided from (used for) investing activities		(39,859	)		481,695

Net change in cash and cash equivalents		-			(18	)
Cash and cash equivalents at beginning of period		732			712
Cash and cash equivalents at end of period	$	732		$	694

The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part
of these statements.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI’s power supply requirements are primarily provided by FES – an affiliated company.

Results of Operations

Net income in the first three months of 2008 decreased to $58 million from $64 million in the same period of 2007. The decrease resulted primarily from higher purchased power costs, increased amortization of regulatory assets and lower investment income, partially offset by the elimination of fuel costs (due to assigning leasehold interests in generating assets to FGCO) and decreases in other operating expenses.

Revenues

Revenues decreased by $4 million, or 1%, in the first three months of 2008 compared to the same period of 2007 primarily due to a decrease in wholesale generation revenues ($32 million), partially offset by an increase in retail generation revenues ($18 million) and distribution revenues ($10 million).

Wholesale generation revenues decreased due to the assignment of CEI’s leasehold interests in the Bruce Mansfield Plant to FGCO on October 16, 2007. Prior to the assignment, CEI sold power from its interests in the plant to FGCO.

Retail generation revenues increased in the first three months of 2008 due to higher average unit prices across all customer classes and increased sales volume to residential and commercial customers compared to the same period of 2007. The higher average unit prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see “Regulatory Matters – Ohio” within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries). More weather-related usage in the first three months of 2008 compared to the same period of 2007 primarily contributed to the increased sales volume in the residential and commercial sectors (heating degree days increased 1.7% from the same period in 2007).

Increases in retail generation sales and revenues in the first three months of 2008 compared to the same period in 2007 are summarized in the following tables:

Retail Generation KWH Sales	Increase

Residential		3.0	%
Commercial		1.8	%
Industrial		1.0	%
Increase in Retail Generation Sales		1.8	%

Retail Generation Revenues	Increase
	(in millions)
Residential	$	7
Commercial		4
Industrial		7
Increase in Generation Revenues	$	18

Revenues from distribution throughput increased by $10 million in the first three months of 2008 compared to the same period of 2007 primarily due higher average unit prices for all customer classes and higher KWH deliveries to residential and commercial customers. The higher average unit prices resulted from a transmission rider increase effective July 1, 2007. The higher KWH deliveries to residential and commercial customers in the first three months of 2008 reflected the weather impacts described above.

Changes in distribution KWH deliveries and revenues in the first three months of 2008 compared to the corresponding period of 2007 are summarized in the following tables.

Distribution KWH Deliveries	Increase

Residential		3.0	%
Commercial		1.3	%
Industrial		1.0	%
Increase in Distribution Deliveries		1.7	%

Distribution Revenues	Increase
	(In millions)
Residential	$	4
Commercial		3
Industrial		3
Net Increase in Distribution Revenues	$	10

Expenses

Total expenses increased by $1 million in the first three months of 2008 compared to the same period of 2007. The following table presents the change from the prior year by expense category:

Expenses - Changes	Increase (Decrease)
	(in millions)
Fuel costs	$	(13	)
Purchased power costs		13
Other operating costs		(10	)
Amortization of regulatory assets		5
Deferral of new regulatory assets		5
General taxes		1
Net Increase in Expenses	$	1

The ~~increase~~absence of fuel costs in ~~purchases~~the first three months of 2008 was due to the ~~higher retail generation sales requirements. The~~assignment of CEI’s leasehold interests in the Mansfield Plant to FGCO on October 16, 2007. Prior to the assignment, CEI incurred fuel expenses related to its leasehold interest in the plant. Higher purchased power costs primarily reflected higher unit ~~costs reflect the increases in the Ohio Companies’ retail generation rates,~~prices, as provided for under the PSA with FES.

Other operating ~~expenses increased $33 million~~costs were lower primarily due to ~~MISO transmission-related expenses. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.~~

~~Other – First Nine Months~~the assignment of ~~2007 Compared to First Nine Months of 2006~~

FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $2 million increase in FirstEnergy’s net incomeCEI’s leasehold interests in the ~~first nine months~~Mansfield plant. Higher amortization of ~~2007.~~regulatory assets were primarily due to increased transition cost amortization due to the higher KWH sales discussed above and increases related to the effective interest methodology. The ~~increase~~change in deferrals of new regulatory assets was primarily due to ~~the sale~~lower deferred MISO expenses (more expenses currently recovered through increased transmission tariffs) and RCP fuel costs (implementation of ~~First Communications ($13 million, net of taxes), the absence of subsidiaries’ preferred stock dividends~~fuel cost recovery rider). The change in ~~2007 ($6 million)~~general taxes is primarily due to higher real and ~~the absence of a $4 million loss included in 2006 results from discontinued operations (see Note 4).~~personal property taxes.

Other Expense

~~CAPITAL RESOURCES AND LIQUIDITY~~Other expense increased by $5 million in the first three months of 2008 compared to the same period of 2007 primarily due to lower investment income, partially offset by a reduction in interest expense. Lower investment income is primarily the result of principal repayments since the first quarter of 2007 on notes receivable from associated companies. The lower interest expense is due to long-term debt redemptions ($489 million) since the first quarter of 2007, partially offset by a debt issuance in the first quarter of 2007 ($250 million).

FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2007 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.Legal Proceedings

~~Changes in Cash Position~~See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to CEI.

~~FirstEnergy's primary source~~New Accounting Standards and Interpretations

See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of ~~cash required~~Registrant Subsidiaries for ~~continuing operations as a holding company is cash from~~discussion of new accounting standards and interpretations applicable to CEI.

Report of Independent Registered Public Accounting Firm

To the ~~operations~~Stockholder and Board of ~~its subsidiaries. FirstEnergy and certain~~Directors of ~~its subsidiaries also~~

The Cleveland Electric Illuminating Company:

We have ~~access to $2.75 billion~~reviewed the accompanying consolidated balance sheet of short-term financing under a revolving credit facility which expires in 2011. Under the terms of the facility, FirstEnergy is permitted to have up to $1.5 billion in outstanding borrowings at any time, subject to the facility cap of $2.75 billion of aggregate outstanding borrowings by itThe Cleveland Electric Illuminating Company and its subsidiaries ~~that~~as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are ~~also parties to such facility. In~~ the ~~first nine months~~responsibility of ~~2007, FirstEnergy received $1.8 billion~~the Company’s management.

We conducted our review in accordance with the standards of ~~cash dividends~~the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and ~~return~~making inquiries of ~~capital from its subsidiaries~~persons responsible for financial and ~~paid $464 million~~accounting matters. It is substantially less in ~~cash dividends to common shareholders. With~~scope than an audit conducted in accordance with the ~~exception~~standards of ~~Met-Ed,~~the Public Company Accounting Oversight Board (United States), the objective of which is ~~currently~~the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 8, Note 4, Note 2(G) and Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an ~~accumulated deficit position, there are no~~unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material ~~restrictions on~~respects in relation to the ~~payment of cash dividends by the subsidiaries of FirstEnergy.~~consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 7, 2008

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2008			2007
	(In thousands)

REVENUES:
Electric sales	$	418,708		$	422,805
Excise tax collections		18,600			18,027
Total revenues		437,308			440,832

EXPENSES:
Fuel		-			13,191
Purchased power		193,244			180,657
Other operating costs		65,118			74,951
Provision for depreciation		19,076			18,468
Amortization of regulatory assets		38,256			33,129
Deferral of new regulatory assets		(29,248	)		(33,957	)
General taxes		40,083			38,894
Total expenses		326,529			325,333

OPERATING INCOME		110,779			115,499

OTHER INCOME (EXPENSE):
Investment income		9,188			17,687
Miscellaneous income		534			731
Interest expense		(32,520	)		(35,740	)
Capitalized interest		196			205
Total other expense		(22,602	)		(17,117	)

INCOME BEFORE INCOME TAXES		88,177			98,382

INCOME TAXES		30,326			34,833

NET INCOME		57,851			63,549

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(213	)		1,202
Income tax expense related to other comprehensive income		281			355
Other comprehensive income (loss), net of tax		(494	)		847

TOTAL COMPREHENSIVE INCOME	$	57,357		$	64,396

The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
Company are an integral part of these statements.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	241		$	232
Receivables-
Customers (less accumulated provisions of $7,224,000 and $7,540,000,		266,701			251,000
respectively, for uncollectible accounts)
Associated companies		70,727			166,587
Other		3,643			12,184
Notes receivable from associated companies		54,679			52,306
Prepayments and other		1,728			2,327
		397,719			484,636
UTILITY PLANT:
In service		2,142,458			2,256,956
Less - Accumulated provision for depreciation		827,160			872,801
		1,315,298			1,384,155
Construction work in progress		40,834			41,163
		1,356,132			1,425,318
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		425,722			463,431
Other		10,275			10,285
		435,997			473,716
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,688,521			1,688,521
Regulatory assets		853,716			870,695
Pension assets		64,497			62,471
Property taxes		76,000			76,000
Other		32,735			32,987
		2,715,469			2,730,674
	$	4,905,317		$	5,114,344
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	207,281		$	207,266
Short-term borrowings-
Associated companies		365,816			531,943
Accounts payable-
Associated companies		139,423			169,187
Other		6,169			5,295
Accrued taxes		118,102			94,991
Accrued interest		37,726			13,895
Other		35,044			34,350
		909,561			1,056,927
CAPITALIZATION:
Common stockholder's equity
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding		873,353			873,536
Accumulated other comprehensive loss		(69,623	)		(69,129	)
Retained earnings		743,278			685,428
Total common stockholder's equity		1,547,008			1,489,835
Long-term debt and other long-term obligations		1,447,980			1,459,939
		2,994,988			2,949,774
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		719,938			725,523
Accumulated deferred investment tax credits		18,102			18,567
Retirement benefits		94,322			93,456
Deferred revenues - electric service programs		21,297			27,145
Lease assignment payable to associated companies		38,420			131,773
Other		108,689			111,179
		1,000,768			1,107,643
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	4,905,317		$	5,114,344

The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
Company are an integral part of these balance sheets.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,

	2008			2007
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	57,851		$	63,549
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		19,076			18,468
Amortization of regulatory assets		38,256			33,129
Deferral of new regulatory assets		(29,248	)		(33,957	)
Deferred rents and lease market valuation liability		-			(46,528	)
Deferred income taxes and investment tax credits, net		(4,965	)		(5,453	)
Accrued compensation and retirement benefits		(3,507	)		(890	)
Pension trust contribution		-			(24,800	)
Decrease in operating assets-
Receivables		90,280			224,011
Prepayments and other current assets		604			592
Increase (decrease) in operating liabilities-
Accounts payable		(28,889	)		(256,808	)
Accrued taxes		23,196			13,959
Accrued interest		23,831			18,122
Electric service prepayment programs		(5,847	)		(5,313	)
Other		(63	)		(167	)
Net cash provided from (used for) operating activities		180,575			(2,086	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			247,715
Redemptions and Repayments-
Long-term debt		(165	)		(150	)
Short-term borrowings, net		(177,960	)		(130,585	)
Dividend Payments-
Common stock		-			(24,000	)
Net cash provided from (used for) financing activities		(178,125	)		92,980

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(37,203	)		(36,682	)
Loans to associated companies, net		(2,373	)		(231,907	)
Collection of principal on long-term notes receivable		-			133,341
Redemptions of lessor notes		37,709			35,614
Other		(574	)		9,294
Net cash used for investing activities		(2,441	)		(90,340	)

Net increase in cash and cash equivalents		9			554
Cash and cash equivalents at beginning of period		232			221
Cash and cash equivalents at end of period	$	241		$	775


The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
Company are an integral part of these statements.

~~On March~~THE TOLEDO EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. TE’s power supply requirements are provided by FES – an affiliated company.

Results of Operations

Net income in the first three months of 2008 decreased to $17 million from $26 million in the same period of 2007. The decrease resulted primarily from lower electric sales revenues, higher purchased power costs and a decrease in the deferral of new regulatory assets, partially offset by lower fuel, nuclear and other operating costs.

Revenues

Revenues decreased $29 million, or 12%, in the first three months of 2008 compared to the same period of 2007 primarily due to lower wholesale generation revenues ($45 million), partially offset by increased retail generation revenues ($11 million) and distribution revenues ($4 million).

The decrease in wholesale revenues resulted primarily from the termination of TE’s Beaver Valley Unit 2 sale agreement with CEI at the end of 2007 ~~FirstEnergy repurchased approximately 14.4 million shares, or approximately 4.5%,~~($26 million) and lower PSA sales to FES in the first three months of ~~its outstanding common stock at an initial price~~2008 ($20 million) due to the assignment of approximately $900 million pursuant to an accelerated share repurchase program. FirstEnergy acquired these shares under its previously announced authorization to repurchase up to 16 million shares of its common stock. The share repurchase was funded with short-term borrowings, which have since been repaid with the proceeds fromTE’s leasehold interests in the Bruce Mansfield Plant to FGCO effective October 16, 2007. In 2008, TE is selling the 158 MW entitlement from its 18.26% leasehold interest in Beaver Valley Unit ~~1 sale and leaseback transaction.~~2 to NGC.

~~On July 13, 2007, FGCO completed~~Retail generation revenues increased in the first three months of 2008 due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers compared to the same period of 2007. Industrial KWH sales decreased due in part to a ~~sale~~maintenance outage for a large industrial customer during the first quarter of 2008. The higher average prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see “Regulatory Matters – Ohio” within the Combined Management’s Discussion and ~~leaseback transaction for its 93.825% undivided interest~~Analysis of Registrant Subsidiaries). The increase in ~~Bruce Mansfield Unit 1, representing 779 MW~~sales volume reflects increased weather-related usage in the first three months of net demonstrated capacity. The purchase price of approximately $1.329 billion (net after-tax proceeds of approximately $1.2 billion) for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds2008 (heating degree days increased 3.3% from the ~~sale~~same period of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034. A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates. The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The notes and certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements. FES’ registration obligations under the registration rights agreement applicable to the $1.135 billion principal amount of pass through certificates issued in connection with the transaction were satisfied in September 2007, at which time the transaction was classified as an operating lease under GAAP for FES and FirstEnergy. This transaction generated tax capital gains of approximately $752 million. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowances in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 3)2007).

~~As of September 30, 2007, FirstEnergy had $30 million of cash~~Changes in retail electric generation KWH sales and ~~cash equivalents compared with $90 million as of December 31, 2006. The major sources of changes in these balances are summarized below.~~

~~Cash Flows From Operating Activities~~

FirstEnergy's consolidated net cash from operating activities is provided primarily by its energy delivery services and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $1.2 billionrevenues in the first ~~nine~~three months of 2008 from the same period of 2007 ~~and 2006~~are summarized ~~as follows:~~in the following tables.

Nine Months Ended

September 30,

Operating Cash Flows

2007

2006

(In millions)

Net income $ 1,041 $ 979
Non-cash charges 358 497
Pension trust contribution (300 ) -
Working capital and other 52 (233 )
$ 1,151 $ 1,243

	Increase
Retail Generation KWH Sales	(Decrease)

Residential		4.4	%
Commercial		5.6	%
Industrial		(4.3	)%
Net Decrease in Retail Generation Sales		(0.1	)%

~~Net cash provided~~

Retail Generation Revenues	Increase
	(In millions)
Residential	$	4
Commercial		3
Industrial		4
Increase in Retail Generation Revenues	$	11

Revenues from ~~operating activities decreased~~distribution throughput increased by ~~$92~~$4 million in the first ~~nine~~three months of ~~2007~~2008 compared to the ~~first nine months of 2006 primarily~~same period in 2007 due to ~~a $300 million pension trust contribution in 2007~~higher average unit prices for all customer classes and ~~a $139 million change in non-cash charges, partially offset by a $285 million change in working capital~~higher KWH deliveries to residential and ~~other and a $62 million increase in net income (see Results of Operations above).~~commercial customers. The decrease in non-cash charges and increase from working capital primarily reflects changes to deferred income taxes and accrued taxes related to the Bruce Mansfield Unit 1 sale and leaseback transaction discussed above. Excluding the tax effects of the sale and leaseback transaction, the changes in working capital and other primarilyhigher average prices resulted from a ~~$322 million~~transmission rider increase ~~in receivables due~~effective July 1, 2007. The higher KWH deliveries to ~~higher sales, partially offset by $92 million from reduced materials~~residential and ~~supplies inventories due primarily to lower coal inventory levels and $78 million of decreased payments for accounts payable, reflecting a change~~commercial customers in the ~~timing of payments from the~~ first ~~nine~~three months of ~~2006.~~2008 reflected the weather impacts described above.

Changes in distribution KWH deliveries and revenues in the first three months of 2008 from the same period of 2007 are summarized in the following tables.

	Increase
Distribution KWH Deliveries	(Decrease)

Residential		3.6	%
Commercial		2.3	%
Industrial		(4.0	)%
Net Decrease in Distribution Deliveries		(0.4	)%

Distribution Revenues	Increase (Decrease)
	(In millions)
Residential	$	3
Commercial		2
Industrial		(1	)
Net Increase in Distribution Revenues	$	4

~~Cash Flows From Financing Activities~~Expenses

~~In the first nine months of 2007, cash used for financing activities was $1.4 billion compared to $444~~Total expenses decreased $15 million in the first ~~nine~~three months of ~~2006.~~2008 from the same period of 2007. The following table presents changes from the prior year by expense category.

Expenses – Changes	Increase (Decrease)
	(In millions)
Fuel costs	$	(9	)
Purchased power costs		5
Nuclear operating costs		(7	)
Other operating costs		(10	)
Amortization of regulatory assets		1
Deferral of new regulatory assets		4
General taxes		1
Net Decrease in Expenses	$	(15	)

Lower fuel costs in the first three months of 2008 compared to the same period of 2007 were due to the assignment of TE’s leasehold interests in the Mansfield Plant to FGCO in October 2007. Higher purchased power costs reflected higher unit prices as provided for under the PSA with FES and a 1.8% increase in KWH purchases. Nuclear operating expenses decreased primarily due to the reversal ($8 million) of the above-market lease liability associated with TE’s leasehold interest in Beaver Valley Unit 2 related to the termination of the CEI sale agreement discussed above. Other operating costs were lower primarily due to the assignment of TE’s leasehold interests in the Mansfield Plant ($9 million). The change in the deferral of new regulatory assets was primarily due to ~~more common shares repurchased~~lower deferred RCP distribution costs ($3 million) and fuel costs ($1 million).

Other Expense

Other expense decreased $2 million in the first three months of 2008 compared to the same period of 2007 ~~than in 2006 and~~primarily due to lower interest expense, partially offset by lower investment income. The lower interest expense resulted from the ~~repayment~~redemption of ~~short-term borrowings in~~long-term debt ($85 million principal amount) since the first quarter of 2007. The ~~following table summarizes security issuances and redemptions.~~decrease in investment income resulted primarily from the principal repayments since the first quarter of 2007 on notes receivable from associated companies.

Nine Months Ended

September 30,

Securities Issued or Redeemed

2007

2006

(In millions)

New issues

Pollution control notes $ - $ 253
Secured notes - 382
Unsecured notes 1,100 600
$ 1,100 $ 1,235
Redemptions

First mortgage bonds $ 287 $ 1
Pollution control notes 4 311
Senior secured notes 203 181
Unsecured notes 153 500
Common stock 918 600
Preferred stock - 107
$ 1,565 $ 1,700

Short-term borrowings, net $ (535 ) $ 482
Legal Proceedings

~~FirstEnergy had approximately $573 million~~See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of ~~short-term indebtedness as~~Registrant Subsidiaries for discussion of ~~September 30, 2007 compared~~legal proceedings applicable to ~~approximately $1.1 billion as of December 31, 2006. Available bank borrowing capability as of September 30, 2007 included the following:~~TE.

Borrowing Capability (In millions)

Short-term credit facilities⁽¹⁾
$ 2,870
Accounts receivable financing facilities 550
Utilized (570 )
LOCs (337 )
Net available capability $ 2,513

⁽¹⁾ ~~Includes the $2.75 billion revolving credit facility described below, a $100 million revolving credit facility that expires in December 2009 and a $20 million uncommitted line of credit.~~

New Accounting Standards and Interpretations

AsSee the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of ~~September 30, 2007, the Ohio Companies~~Registrant Subsidiaries for discussion of new accounting standards and ~~Penn had the aggregate capability~~interpretations applicable to issue approximately $3.1 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $543 million, $459 million and $112 million, respectively, as of September 30, 2007. JCP&L satisfied the provision of its senior note indenture for the release of all FMBs held as collateral for senior notes in May 2007, subsequently repaid its other remaining FMBs and, effective September 14, 2007, discharged and released its mortgage indenture.TE.

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of ~~September 30, 2007, approximately $1.0 billion~~

Directors of ~~capacity remained unused under an existing FirstEnergy shelf registration statement filed~~The Toledo Edison Company:

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the ~~SEC~~standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in 2003 to support future securities issuances. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units. As of September 30, 2007, OE had approximately $400 million of capacity remaining unused under a shelf registration for unsecured debt securities filedscope than an audit conducted in accordance with the ~~SEC in 2006.~~standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

~~FirstEnergy and certain~~Based on our review, we are not aware of ~~its subsidiaries are parties~~any material modifications that should be made to ~~a $2.75 billion five-year revolving credit facility (included~~the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the ~~borrowing capability table above). FirstEnergy may request~~United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007 and defined benefit pension and other postretirement plans as of December 31, 2006, as discussed in Note 8 and Note 4 to the consolidated financial statements) dated February 28, 2008, we expressed an ~~increase~~unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the ~~total commitments available under this facility up~~accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to ~~a maximum of $3.25 billion. Commitments under~~ the 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.

The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations:

Revolving

Regulatory and

Credit Facility

Other Short-Term

Borrower

Sub-Limit

Debt Limitations⁽¹⁾

(In millions)

FirstEnergy
$ 2,750 $ -
⁽²⁾
OE
500 500
Penn
50 41
CEI
250
⁽³⁾
500
TE
250
⁽³⁾
500
JCP&L
425 423
Met-Ed
250 250
⁽⁴⁾
Penelec
250 250
⁽⁴⁾
FES
250 -
⁽²⁾
ATSI
-
⁽⁵⁾
50

consolidated balance sheet from which it has been derived.

⁽¹⁾

~~As of September 30, 2007.~~

⁽²⁾

~~No regulatory approvals, statutory or charter limitations applicable.~~

⁽³⁾

Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s.

⁽⁴⁾

~~Excluding amounts which may be borrowed under the regulated money pool.~~

⁽⁵⁾

The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) such borrower has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed the obligations of such borrower under the facility.

The revolving credit facility, combined with an aggregate $550 million ($255 million unused as of September 30, 2007) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet working capital requirements and for other general corporate purposes for FirstEnergy and its subsidiaries.

~~Borrower~~
~~FirstEnergy~~PricewaterhouseCoopers LLP	57	%
OECleveland, Ohio	47	%
~~Penn~~May 7, 2008	21	%
~~CEI~~	60	%
TE	55	%
~~JCP&L~~	31	%
~~Met-Ed~~	46	%
~~Penelec~~	50	%
~~FES~~	48	%

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2008			2007
	(In thousands)

REVENUES:
Electric sales	$	203,669		$	233,056
Excise tax collections		8,025			7,400
Total revenues		211,694			240,456

EXPENSES:
Fuel		1,482			10,147
Purchased power		101,298			96,169
Nuclear operating costs		10,457			17,721
Other operating costs		33,390			42,921
Provision for depreciation		9,025			9,117
Amortization of regulatory assets		25,025			23,876
Deferral of new regulatory assets		(9,494	)		(13,481	)
General taxes		14,377			13,734
Total expenses		185,560			200,204

OPERATING INCOME		26,134			40,252

OTHER INCOME (EXPENSE):
Investment income		6,481			7,225
Miscellaneous expense		(1,514	)		(3,100	)
Interest expense		(6,035	)		(7,503	)
Capitalized interest		37			83
Total other expense		(1,031	)		(3,295	)

INCOME BEFORE INCOME TAXES		25,103			36,957

INCOME TAXES		8,088			11,097

NET INCOME		17,015			25,860

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(63	)		573
Change in unrealized gain on available-for-sale securities		1,961			379
Other comprehensive income		1,898			952
Income tax expense related to other comprehensive income		728			334
Other comprehensive income, net of tax		1,170			618

TOTAL COMPREHENSIVE INCOME	$	18,185		$	26,478

The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company
are an integral part of these statements.

THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,				December 31,
		2008			2007
		(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	213		$	22
Receivables-
Customers			966			449
Associated companies			42,232			88,796
Other (less accumulated provisions of $471,000 and $615,000,
respectively, for uncollectible accounts)			4,241			3,116
Notes receivable from associated companies			107,664			154,380
Prepayments and other			684			865
			156,000			247,628
UTILITY PLANT:
In service			854,457			931,263
Less - Accumulated provision for depreciation			397,670			420,445
			456,787			510,818
Construction work in progress			28,735			19,740
			485,522			530,558
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			142,657			154,646
Long-term notes receivable from associated companies			37,457			37,530
Nuclear plant decommissioning trusts			69,491			66,759
Other			1,734			1,756
			251,339			260,691
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			500,576			500,576
Regulatory assets			187,579			203,719
Pension assets			29,420			28,601
Property taxes			21,010			21,010
Other			28,959			20,496
			767,544			774,402
		$	1,660,405		$	1,813,279
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	34		$	34
Accounts payable-
Associated companies			56,448			245,215
Other			3,973			4,449
Notes payable to associated companies			66,217			13,396
Accrued taxes			37,085			30,245
Lease market valuation liability			36,900			36,900
Other			51,563			22,747
			252,220			352,986
CAPITALIZATION:
Common stockholder's equity-
Common stock, $5 par value, authorized 60,000,000 shares -
29,402,054 shares outstanding			147,010			147,010
Other paid-in capital			173,141			173,169
Accumulated other comprehensive loss			(9,436	)		(10,606	)
Retained earnings			192,633			175,618
Total common stockholder's equity			503,348			485,191
Long-term debt and other long-term obligations			303,392			303,397
			806,740			788,588
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			99,732			103,463
Accumulated deferred investment tax credits			9,967			10,180
Lease market valuation liability			300,775			310,000
Retirement benefits			64,422			63,215
Asset retirement obligations			28,744			28,366
Deferred revenues - electric service programs			9,969			12,639
Lease assignment payable to associated companies			28,835			83,485
Other			59,001			60,357
			601,445			671,705
COMMITMENTS AND CONTINGENCIES (Note 10)
		$	1,660,405		$	1,813,279

The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company
are an integral part of these balance sheets.

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2008			2007
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	17,015		$	25,860
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		9,025			9,117
Amortization of regulatory assets		25,025			23,876
Deferral of new regulatory assets		(9,494	)		(13,481	)
Deferred rents and lease market valuation liability		6,099			(10,891	)
Deferred income taxes and investment tax credits, net		(3,404	)		(3,639	)
Accrued compensation and retirement benefits		(1,813	)		(756	)
Pension trust contribution		-			(7,659	)
Decrease in operating assets-
Receivables		45,738			158
Prepayments and other current assets		181			312
Increase (decrease) in operating liabilities-
Accounts payable		(189,243	)		(17,533	)
Accrued taxes		6,840			9,379
Accrued interest		4,663			3,951
Electric service prepayment programs		(2,670	)		(2,616	)
Other		991			(541	)
Net cash provided from (used for) operating activities		(91,047	)		15,537

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		52,821			-
Redemptions and Repayments-
Long-term debt		(9	)		-
Short-term borrowings, net		-			(46,518	)
Net cash provided from (used for) financing activities		52,812			(46,518	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(19,435	)		(6,064	)
Loans repayments from (loans to) associated companies, net		46,789			(8,583	)
Collection of principal on long-term notes receivable		-			32,202
Redemption of lessor notes		11,989			14,804
Sales of investment securities held in trusts		3,908			16,863
Purchases of investment securities held in trusts		(4,715	)		(17,642	)
Other		(110	)		(420	)
Net cash provided from investing activities		38,426			31,160

Net increase in cash and cash equivalents		191			179
Cash and cash equivalents at beginning of period		22			22
Cash and cash equivalents at end of period	$	213		$	201

The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an
integral part of these statements.

The revolving credit facility does not contain provisions that either restrict the 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 the credit ratings of the company borrowing the funds.JERSEY CENTRAL POWER & LIGHT COMPANY

~~FirstEnergy's~~MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated ~~companies~~electric transmission and distribution services. JCP&L also ~~have~~provides generation services to those customers electing to retain JCP&L as their power supplier.

Results of Operations

Net income for the ~~ability~~first three months of 2008 decreased to ~~borrow~~$34 million from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is$38 million in the same ~~for each company receiving a loan from their respective pool~~period in 2007. The decrease was primarily due to higher other operating costs, partially offset by higher non-generation revenues.

Revenues

In the first three months of 2008, revenues increased $111 million, or 16.5%, as compared with the same period of 2007. Retail and ~~is based on the average cost of funds available through the pool. The average interest rate for borrowings~~wholesale generation revenues increased by $73 million and $38 million, respectively, in the first ~~nine~~three months of ~~2007 was 5.66% for the regulated companies’ money pool and 5.65% for the unregulated companies’ money pool.~~2008.

~~FirstEnergy’s access~~Retail generation revenues from all customer classes increased in the first three months of 2008 compared to ~~capital markets~~the same period of 2007 due to higher unit prices resulting from the BGS auction effective June 1, 2007, partially offset by a slight decrease in retail generation KWH sales. Sales volume decreased primarily due to milder weather in the first three months of 2008 (heating degree days were 6.7% lower than the first three months of 2007) and ~~costs~~an increase in customer shopping in the commercial and industrial customer sectors by 3.6 percentage points and 3.0 percentage points, respectively.

Wholesale generation revenues increased $38 million in the first three months of ~~financing~~2008 due to higher market prices, partially offset by a slight decrease in sales volumes as compared to the first three months of 2007.

Changes in retail generation KWH sales and revenues by customer class in the first three months of 2008 compared to the same period of 2007 are ~~influenced by~~summarized in the ~~ratings of its securities. The~~ following table displays FirstEnergy’s, FES’ and the Companies’ securities ratings as of October 18, 2007. The ratings outlook from Moody’s is stable for FES and positive for all other companies. The ratings outlook from S&P on all securities is negative.tables:

~~Issuer~~ Retail Generation KWH Sales	Increase ~~Securities~~ (Decrease)
~~S&P~~
Residential		0.1	%
Commercial		(3.4	)%
Industrial		(12.4	)%
Net Decrease in Generation Sales		(1.9	)%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	43
Commercial		28
Industrial		2
Increase in Generation Revenues	$	73

Distribution revenues increased in the first three months of 2008 as compared to the same period of 2007 due to slight increases in composite unit prices and KWH deliveries.

Changes in distribution KWH deliveries in the first three months of 2008 compared to the same period in 2007 are summarized in the following table:

~~Moody’s~~

	Increase
Distribution KWH Deliveries	(Decrease)

Residential		0.1	%
Commercial		1.2	%
Industrial		(1.3	)%
Net Increase in Distribution Deliveries		0.4	%

Expenses

Total expenses increased by $113 million in the first three months of 2008 as compared to the same period of 2007. The following table presents changes from the prior year period by expense category:

Expenses - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	110
Other operating costs		4
Provision for depreciation		3
Amortization of regulatory assets		(4	)
Net increase in expenses	$	113

Purchased power costs increased in the first three months of 2008 primarily due to higher unit prices resulting from the BGS auction effective June 1, 2007, partially offset by a decrease in purchases due to the lower KWH sales discussed above. Other operating costs increased in the first three months of 2008 primarily due to higher expenses related to JCP&L’s customer assistance programs. Depreciation expense increased primarily due to an increase in depreciable property since the first quarter of 2007. Amortization of regulatory assets decreased in the first three months of 2008 primarily due to the completion in December 2007 of certain regulatory asset amortizations associated with TMI-2.

Other Expenses

Other expenses increased by $6 million in the first three months of 2008 as compared to the same period in 2007 primarily due to interest expense associated with JCP&L’s $550 million issuance of senior notes in May 2007 ($3 million) and reduced income on life insurance investments ($2 million).

Sale of Investment

On April 17, 2008, JCP&L closed on the sale of its 86-MW Forked River Power Plant to Maxim Power Corp. for $20 million. In conjunction with this sale, FES entered into a 10-year tolling agreement with Maxim for the entire capacity of the plant. The sale is subject to regulatory accounting and will not have a material impact on the JCP&L’s earnings in the second quarter of 2008. The New Jersey Rate Counsel has appealed the NJBPU’s approval of the sale to the Appellate Division of the Superior Court of New Jersey, where it is currently pending.

Legal Proceedings

New Accounting Standards and Interpretations

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Jersey Central Power & Light Company:

We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007 and defined benefit pension and other postretirement plans as of December 31, 2006, as discussed in Note 8 and Note 4 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~FirstEnergy~~

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 7, 2008

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,
	2008			2007
	(In thousands)

REVENUES:
Electric sales	$	781,433		$	670,907
Excise tax collections		12,795			12,836
Total revenues		794,228			683,743

EXPENSES:
Purchased power		496,681			386,497
Other operating costs		78,784			74,651
Provision for depreciation		23,282			20,516
Amortization of regulatory assets		91,519			95,228
General taxes		17,028			16,999
Total expenses		707,294			593,891

OPERATING INCOME		86,934			89,852

OTHER INCOME (EXPENSE):
Miscellaneous income (expense)		(389	)		3,061
Interest expense		(24,464	)		(22,416	)
Capitalized interest		276			513
Total other expense		(24,577	)		(18,842	)

INCOME BEFORE INCOME TAXES		62,357			71,010

INCOME TAXES		28,403			32,664

NET INCOME		33,954			38,346

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(3,449	)		(2,115	)
Unrealized gain on derivative hedges		69			97
Other comprehensive loss		(3,380	)		(2,018	)
Income tax benefit related to other comprehensive loss		(1,470	)		(984	)
Other comprehensive loss, net of tax		(1,910	)		(1,034	)

TOTAL COMPREHENSIVE INCOME	$	32,044		$	37,312

The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	40		$	94
Receivables-
Customers (less accumulated provisions of $3,400,000 and $3,691,000,
respectively, for uncollectible accounts)		299,104			321,026
Associated companies		1,757			21,297
Other		53,553			59,244
Notes receivable - associated companies		18,410			18,428
Prepaid taxes		1,302			1,012
Other		20,609			17,603
		394,775			438,704
UTILITY PLANT:
In service		4,208,016			4,175,125
Less - Accumulated provision for depreciation		1,524,495			1,516,997
		2,683,521			2,658,128
Construction work in progress		98,143			90,508
		2,781,664			2,748,636
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		176,107			176,512
Nuclear plant decommissioning trusts		168,056			175,869
Other		2,054			2,083
		346,217			354,464
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		1,475,802			1,595,662
Goodwill		1,825,716			1,826,190
Pension assets		106,211			100,615
Other		15,107			16,307
		3,422,836			3,538,774
	$	6,945,492		$	7,080,578
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	27,735		$	27,206
Short-term borrowings-
Associated companies		82,380			130,381
Accounts payable-
Associated companies		18,699			7,541
Other		168,178			193,848
Accrued taxes		32,968			3,124
Accrued interest		26,656			9,318
Other		107,879			103,286
		464,495			474,704
CAPITALIZATION:
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares-
14,421,637 shares outstanding		144,216			144,216
Other paid-in capital		2,655,248			2,655,941
Accumulated other comprehensive loss		(21,791	)		(19,881	)
Retained earnings		201,542			237,588
Total common stockholder's equity		2,979,215			3,017,864
Long-term debt and other long-term obligations		1,554,064			1,560,310
		4,533,279			4,578,174
NONCURRENT LIABILITIES:
Power purchase contract loss liability		682,481			749,671
Accumulated deferred income taxes		798,967			800,214
Nuclear fuel disposal costs		194,034			192,402
Asset retirement obligations		91,025			89,669
Other		181,211			195,744
		1,947,718			2,027,700
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	6,945,492		$	7,080,578

The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these balance sheets.

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	33,954		$	38,346
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		23,282			20,516
Amortization of regulatory assets		91,519			95,228
Deferred purchased power and other costs		(40,293	)		(78,303	)
Deferred income taxes and investment tax credits, net		723			8,076
Accrued compensation and retirement benefits		(15,113	)		(8,374	)
Cash collateral from (returned to) suppliers		(502	)		1
Pension trust contribution		-			(17,800	)
Decrease (increase) in operating assets:
Receivables		48,733			(23,381	)
Materials and supplies		255			(1	)
Prepaid taxes		(290	)		11,946
Other current assets		(1,305	)		454
Increase (decrease) in operating liabilities:
Accounts payable		(14,511	)		(62,038	)
Accrued taxes		29,844			31,599
Accrued interest		17,338			9,794
Other		13,302			(555	)
Net cash provided from operating activities		186,936			25,508

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		-			37,071
Redemptions and Repayments-
Long-term debt		(5,872	)		(9,569	)
Short-term borrowings, net		(48,069	)		-
Dividend Payments-
Common stock		(70,000	)		(15,000	)
Net cash provided from (used for) financing activities		(123,941	)		12,502

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(56,047	)		(40,015	)
Loan repayments from associated companies, net		18			532
Sales of investment securities held in trusts		56,506			26,436
Purchases of investment securities held in trusts		(61,290	)		(30,437	)
Other		(2,236	)		5,479
Net cash used for investing activities		(63,049	)		(38,005	)

Net change in cash and cash equivalents		(54	)		5
Cash and cash equivalents at beginning of period		94			41
Cash and cash equivalents at end of period	$	40		$	46

The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.

METROPOLITAN EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier.

Results of Operations

Net income decreased to $22 million in the first quarter of 2008, compared to $32 million in the same period of 2007. The decrease was primarily due to higher purchased power costs, increased other operating costs and a decrease in the deferral of new regulatory assets, partially offset by higher revenues.

Revenues

Revenues increased by $30 million, or 8.1%, in the first quarter of 2008, compared to the same period of 2007, primarily due to higher retail and wholesale generation revenues combined with higher distribution throughput revenues, partially offset by a decrease in PJM transmission revenues.

In the first quarter of 2008, retail generation revenues increased $6 million primarily due to higher KWH sales to the residential and commercial customer classes and higher composite unit prices in all customer classes, partially offset by lower KWH sales to the industrial customer class.

Changes in retail generation sales and revenues in the first quarter of 2008 compared to the same period of 2007 are summarized in the following tables:

	~~Senior unsecured~~Increase
Retail Generation KWH Sales	~~BBB-~~(Decrease)			~~Baa3~~

Residential		4.6	%
Commercial		4.1	%
Industrial		(1.8	)%
Net Increase in Retail Generation Sales		2.7	%

	Increase
OERetail Generation Revenues	~~Senior unsecured~~(Decrease)
	~~BBB-~~(In millions)
Residential	~~Baa2~~ $	4
Commercial		3
Industrial		(1	)
Net Increase in Retail Generation Revenues	$	6

Wholesale revenues increased by $27 million in the first quarter of 2008, compared to the same period of 2007, primarily reflecting higher spot market prices for PJM market participants.

Revenues from distribution throughput increased $4 million in the first quarter of 2008, compared to the same period in 2007, due to higher KWH deliveries in the residential and commercial customer classes, partially offset by decreased KWH deliveries to industrial customers.

Changes in distribution KWH deliveries and revenues in the first quarter of 2008 compared to the same period of 2007 are summarized in the following tables:

	Increase
Distribution KWH Deliveries	(Decrease)

Residential		4.6	%
~~CEI~~Commercial	~~Senior secured~~	4.1	%
Industrial	~~BBB+~~	(1.8	)%
Net Increase in Distribution Deliveries	~~Baa2~~	2.7	%

Distribution Revenues	Increase
	~~Senior unsecured~~(In millions)
Residential	~~BBB-~~ $	1
Commercial	~~Baa3~~	3
Industrial		-
Increase in Distribution Revenues	$	4

PJM transmission revenues decreased by $7 million in the first quarter of 2008 compared to the same period of 2007, primarily due to decreased PJM FTR revenue. Met-Ed defers the difference between revenue from its transmission rider and transmission costs incurred, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses increased by $42 million in the first quarter of 2008 compared to the same period of 2007. The following table presents changes from the prior year by expense category:

Expenses – Changes	Increase
	(In millions)
Purchased power costs	$	25
Other operating costs		9
Provision for depreciation		1
Amortization of regulatory assets		1
Deferral of new regulatory assets		5
General taxes		1
Increase in expenses	$	42

Purchased power costs increased by $25 million in the first quarter of 2008, primarily due to higher composite unit prices combined with increased KWH purchased to source increased generation sales. Other operating costs increased by $9 million in the first quarter of 2008 primarily due to higher transmission expenses associated with increased transmission volumes and increased labor and contractor service expenses for storm restoration work performed during the first quarter of 2008.

The deferral of new regulatory assets decreased in the first quarter of 2008 primarily due to the absence of the 2007 deferral of decommissioning costs ($15 million) associated with the Saxton nuclear research facility (see Note 11(C)), partially offset by increased transmission cost deferrals.

Other Expense

Other expense increased in the first quarter of 2008 primarily due to a decrease in interest earned on regulatory assets, reflecting a lower regulatory asset base, combined with an increase in other expenses, primarily due to reduced income from life insurance investments.

Legal Proceedings

New Accounting Standards and Interpretations

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Metropolitan Edison Company:

We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 8, Note 4, Note 2(G) and Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 7, 2008

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2008			2007
	(In thousands)

REVENUES:
Electric sales	$	379,608		$	352,136
Gross receipts tax collections		20,718			18,120
Total revenues		400,326			370,256

EXPENSES:
Purchased power		216,982			191,589
Other operating costs		107,017			98,018
Provision for depreciation		11,112			10,284
Amortization of regulatory assets		35,575			34,140
Deferral of new regulatory assets		(37,772	)		(42,726	)
General taxes		21,781			21,052
Total expenses		354,695			312,357

OPERATING INCOME		45,631			57,899

OTHER INCOME (EXPENSE):
Interest income		5,479			7,726
Miscellaneous income (expense)		(309	)		1,109
Interest expense		(11,672	)		(11,756	)
Capitalized interest		(219	)		260
Total other expense		(6,721	)		(2,661	)

INCOME BEFORE INCOME TAXES		38,910			55,238

INCOME TAXES		16,675			23,599

NET INCOME		22,235			31,639

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(2,233	)		(1,452	)
Unrealized gain on derivative hedges		84			84
Other comprehensive loss		(2,149	)		(1,368	)
Income tax benefit related to other comprehensive loss		(970	)		(692	)
Other comprehensive loss, net of tax		(1,179	)		(676	)

TOTAL COMPREHENSIVE INCOME	$	21,056		$	30,963

The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company
are an integral part of these statements.

METROPOLITAN EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	132		$	135
Receivables-
Customers (less accumulated provisions of $4,483,000 and $4,327,000,
respectively, for uncollectible accounts)		144,865			142,872
Associated companies		55,776			27,693
Other		20,673			18,909
Notes receivable from associated companies		12,828			12,574
Prepaid taxes		56,202			14,615
Other		850			1,348
		291,326			218,146
UTILITY PLANT:
In service		1,997,131			1,972,388
Less - Accumulated provision for depreciation		758,228			751,795
		1,238,903			1,220,593
Construction work in progress		32,946			30,594
		1,271,849			1,251,187
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		271,771			286,831
Other		1,377			1,360
		273,148			288,191
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		424,070			424,313
Regulatory assets		530,006			494,947
Pension assets		54,198			51,427
Other		31,097			36,411
		1,039,371			1,007,098
	$	2,875,694		$	2,764,622
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Short-term borrowings-
Associated companies	$	167,070		$	185,327
Other		250,000			100,000
Accounts payable-
Associated companies		25,556			29,855
Other		56,797			66,694
Accrued taxes		1,501			16,020
Accrued interest		7,059			6,778
Other		25,191			27,393
		533,174			432,067
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,000 shares outstanding		1,202,833			1,203,186
Accumulated other comprehensive loss		(16,576	)		(15,397	)
Accumulated deficit		(116,922	)		(139,157	)
Total common stockholder's equity		1,069,335			1,048,632
Long-term debt and other long-term obligations		513,661			542,130
		1,582,996			1,590,762
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		456,126			438,890
Accumulated deferred investment tax credits		8,234			8,390
Nuclear fuel disposal costs		43,831			43,462
Asset retirement obligations		163,239			160,726
Retirement benefits		7,621			8,681
Other		80,473			81,644
		759,524			741,793
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	2,875,694		$	2,764,622

The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these balance sheets.

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2008			2007
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	22,235		$	31,639
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		11,112			10,284
Amortization of regulatory assets		35,575			34,140
Deferred costs recoverable as regulatory assets		(10,628	)		(19,160	)
Deferral of new regulatory assets		(37,772	)		(42,726	)
Deferred income taxes and investment tax credits, net		17,307			16,178
Accrued compensation and retirement benefits		(9,655	)		(7,683	)
Cash collateral		-			3,050
Pension trust contribution		-			(11,012	)
Increase in operating assets-
Receivables		(30,863	)		(49,818	)
Prepayments and other current assets		(41,088	)		(27,131	)
Increase (decrease) in operating liabilities-
Accounts payable		(14,196	)		(58,986	)
Accrued taxes		(14,519	)		(9,835	)
Accrued interest		281			1,243
Other		3,892			3,939
Net cash used for operating activities		(68,319	)		(125,878	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		131,743			150,619
Redemptions and Repayments-
Long-term debt		(28,515	)		-
Net cash provided from financing activities		103,228			150,619

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(31,296	)		(18,803	)
Sales of investment securities held in trusts		40,513			25,323
Purchases of investment securities held in trusts		(43,391	)		(28,519	)
Loans to associated companies, net		(254	)		(2,822	)
Other		(484	)		79
Net cash used for investing activities		(34,912	)		(24,742	)

Net change in cash and cash equivalents		(3	)		(1	)
Cash and cash equivalents at beginning of period		135			130
Cash and cash equivalents at end of period	$	132		$	129

The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are
an integral part of these statements.

PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier.

Results of Operations

Net income decreased to $21 million in the first quarter of 2008, compared to $32 million in the same period of 2007. The decrease was primarily due to increased purchased power costs and other operating costs and a decrease in the deferral of new regulatory assets, partially offset by higher revenues.

Revenues

Revenues increased by $40 million, or 11.1%, in the first quarter of 2008 as compared to the same time period of 2007, primarily due to higher retail and wholesale generation revenues, distribution throughput revenues and PJM transmission revenues.

In the first quarter of 2008, retail generation revenues increased $5 million primarily due to higher KWH sales to the residential and commercial customer classes and higher composite unit prices in all customer classes, partially offset by lower KWH sales to the industrial customer class.

Changes in retail generation sales and revenues in the first quarter of 2008 compared to the same period of 2007 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)

Residential		4.5	%
TECommercial	~~Senior unsecured~~	3.0	%
Industrial	~~BBB-~~	(1.6	)%
Net Increase in Retail Generation Sales	~~Baa3~~	2.2	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	3
Commercial		2
Industrial		-
Increase in Retail Generation Revenues	$	5

Wholesale revenues increased $21 million in the first quarter of 2008, compared to the same period of 2007, primarily reflecting higher spot market prices for PJM market participants.

Revenues from distribution throughput increased $4 million in the first quarter of 2008 compared to the same period of 2007, due to increased usage in the residential and commercial customer classes, partially offset by decreased KWH deliveries to industrial customers.

Changes in distribution KWH deliveries and revenues in the first quarter of 2008 compared to the same period of 2007 are summarized in the following tables:

Distribution KWH Deliveries	Increase (Decrease)

~~Penn~~	~~Senior secured~~		A-	~~Baa1~~
Residential		4.5	%
Commercial		3.0	%
~~JCP&L~~	~~Senior unsecured~~		~~BBB~~	~~Baa2~~
Industrial		(1.5	)%
Net Increase in Retail Generation Sales
~~Met-Ed~~2.1	~~Senior unsecured~~		~~BBB~~	~~Baa2~~

~~Penelec~~	~~Senior unsecured~~		~~BBB~~	~~Baa2~~

~~FES~~	~~Corporate Credit/Issuer Rating~~		~~BBB~~	~~Baa2~~%

Distribution Revenues	Increase
	(In millions)
Residential	$	2
Commercial		2
Industrial		-
Increase in Retail Generation Revenues	$	4

~~On February 21, 2007, FirstEnergy made a $700~~PJM transmission revenues increased by $10 million ~~equity investment~~ in ~~FES, all~~the first quarter of ~~which was subsequently contributed to FGCO and used to pay down generation asset transfer-related promissory notes owed~~2008 compared to the ~~Ohio Companies and Penn. OE used its $500 million of proceeds to repurchase shares of its common stock from FirstEnergy.~~

On March 27, 2007, CEI issued $250 million of 5.70% unsecured senior notes due 2017. The proceeds of the offering were used to reduce CEI’s short-term borrowings and for general corporate purposes.

On May 21, 2007, JCP&L issued $550 million of senior unsecured debt securities, consisting of $250 million of 5.65% senior notes due 2017 and $300 million of 6.15% senior notes due 2037. A portion of the proceeds of the offering were used to redeem outstanding FMB of JCP&L comprised of $125 million principal amount of 7.50% series and $150 million principal amount of 6.75% series. On July 1, 2007, JCP&L also redeemed all $12.2 million outstanding principal amount of its remaining series of FMB. In addition, $125 million of proceeds were used to repurchase shares of its common stock from FirstEnergy. The remaining proceeds were used for general corporate purposes.

As described above, on July 13, 2007, FGCO completed the sale and leaseback of a 93.825% undivided interest in Unit 1 of the Bruce Mansfield Generating Plant. Net after-tax proceeds of approximately $1.2 billion from the transaction were used to repay short-term borrowings from, and to invest in, the FirstEnergy non-utility money pool. The repayments and investment allowed FES to reduce its investment in that money pool in order to repay approximately $250 million of external bank borrowings and fund a $600 million equity repurchase from FirstEnergy. FirstEnergy used these funds to reduce its external short term borrowings as discussed above.

On August 30, 2007, Penelec issued $300 million of 6.05% unsecured senior notes due 2017. A portion of the net proceeds from the issuance and sale of the senior notes were used to fund the repurchase of $200 million of Penelec’s common stock from FirstEnergy. The remaining net proceeds were used to repay short-term borrowings and for general corporate purposes.

~~On October 4, 2007, FGCO and NGC closed on the issuance of $427 million of pollution control revenue bonds (PCRBs). Proceeds from the issuance will be used to redeem, during the fourth quarter~~same period of 2007, ~~an equal amount of outstanding PCRBs originally issued on behalf of~~primarily due to higher transmission volumes. Penelec defers the ~~Ohio Companies. This transaction brings the~~difference between revenue from its transmission rider and total ~~amount of PCRBs transferred from the Ohio Companies and Penn~~transmission costs incurred, resulting in no material effect to FGCO and NGC to approximately $1.9 billion, with approximately $265 million remaining to be transferred. The transfer of these PCRBs supports the intra-system generation asset transfer that was completed in 2005.current period earnings.

~~Cash Flows From Investing Activities~~Operating Expenses

~~Net cash flows provided from investing activities resulted principally from~~Total operating expenses increased by $49 million in the ~~proceeds from~~first quarter of 2008 as compared with the Bruce Mansfield Unit 1 sale and leaseback transaction, partially offset by property additions. Energy delivery services expenditures for property additions primarily include expenditures related to transmission and distribution facilities. Capital expenditures by the competitive energy services segment are principally generation-related.same period of 2007. The following table ~~summarizes investing activities for~~presents changes from the ~~nine months ended September 30, 2007 and 2006~~prior year by ~~segment:~~expense category:

Summary of Cash Flows

Property

Provided from (Used for) Investing Activities

Additions

Investments

Other

Total

Sources (Uses)

(In millions)

Nine Months Ended September 30, 2007

Energy delivery services

$
(609
)
$
34

$
(2
)
$
(577
)
Competitive energy services

(462
)

1,345

(1
)
882

Other

(56
)

(5
)
2

(59
)
Inter-Segment reconciling items

-

(15
)
-

(15
)
Total

$
(1,127
)
$
1,359

$
(1
)
$
231

Nine Months Ended September 30, 2006

Energy delivery services

$
(489
)
$
196

$
(8
)
$
(301
)
Competitive energy services

(473
)

(7
)

(1
)
(481
)
Other

(28
)

31

20

23

Inter-Segment reconciling items

-

(63
)

-

(63
)
Total

$
(990
)
$
157

$
11

$
(822
)


Expenses - Changes	Increase
	(In millions)
Purchased power costs	$		20
Other operating costs		12
Provision for depreciation		1
Amortization of regulatory assets		1
Deferral of new regulatory assets		13
General taxes		2
Increase in expenses	$	49

Purchased power costs increased by $20 million, or 10.2%, in the first quarter of 2008 compared to the same period of 2007, primarily due to increased composite unit prices combined with higher KWH purchases to source increased retail and wholesale generation sales. Other operating costs increased by $12 million in the first quarter of 2008 principally due to higher congestion costs and other transmission expenses associated with increased transmission volumes.

The deferral of new regulatory assets decreased in the first quarter of 2008 primarily due to the absence of the 2007 deferral of decommissioning costs ($12 million) associated with the Saxton nuclear research facility (see Note 11) and a decrease in transmission cost deferrals.

In the first ~~nine months~~quarter of ~~2007, net cash provided from investing activities was $231~~2008, general taxes increased $2 million as compared to $822 million used for investing activities in the first nine months of 2006. The change was principally due to $1.3 billion in proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction described above. Partially offsetting the cash proceeds from the sale and leaseback transaction was a $137 million increase in property additions and a $61 million decrease in cash provided from cash investments, primarily from the use of restricted cash investments to repay debt during 2006.

During the remaining three months of 2007, capital requirements for property additions and capital leases are expected to be approximately $460 million. FirstEnergy and the Companies have additional requirements of approximately $10 million for maturing long-term debt during the remainder of 2007. These cash requirements are expected to be satisfied from a combination of internal cash, short-term credit arrangements, and funds raised in the capital markets.

FirstEnergy's capital spending for the period 2007-2011 is expected to be nearly $8.0 billion (excluding nuclear fuel), of which approximately $1.5 billion applies to 2007. Investments for additional nuclear fuel during the 2007-2011 period are estimated to be approximately $1.2 billion, of which about $95 million applies to 2007. During the same period ~~FirstEnergy's nuclear fuel investments are expected~~of 2007, primarily due to ~~be reduced by approximately $810 million and $100 million, respectively, as the nuclear fuel is consumed.~~higher gross receipts taxes.

~~GUARANTEES AND OTHER ASSURANCES~~Other Expense

~~As part~~In the first quarter of ~~normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries~~2008, other expense increased primarily due to ~~provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds,~~higher interest expense associated with Penelec’s $300 million senior note issuance in August 2007 and ~~LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon FirstEnergy’s credit ratings.~~reduced income from life insurance investments.

AsLegal Proceedings

See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of ~~September 30, 2007, FirstEnergy’s maximum exposure~~Registrant Subsidiaries for discussion of legal proceedings applicable to ~~potential future payments under outstanding guarantees~~Penelec.

New Accounting Standards and ~~other assurances approximated $4.7 billion, as summarized below:~~Interpretations

6176

Maximum

Guarantees and Other Assurances

Exposure

(In millions)

FirstEnergy Guarantees of Subsidiaries
Energy and Energy-Related Contracts ⁽¹⁾
$ 647
LOC (long-term debt) – interest coverage ⁽²⁾
9
Other ⁽³⁾
575
1,231

Subsidiaries’ Guarantees
Energy and Energy-Related Contracts 37
LOC (long-term debt) – interest coverage ⁽²⁾
3
Other ⁽⁴⁾
2,686
2,726

Surety Bonds 75
LOC (long-term debt) – interest coverage ⁽²⁾
5
LOC (non-debt) ⁽⁵⁾⁽⁶⁾
690

Total Guarantees and Other Assurances $ 4,727

Report of Independent Registered Public Accounting Firm

⁽¹⁾

~~Issued for open-ended terms, with a 10-day termination right by FirstEnergy.~~

To the Stockholder and Board of

Directors of Pennsylvania Electric Company:

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 8, Note 4, Note 2(G) and Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

⁽²⁾

Reflects the interest coverage portion of LOCs issued in support of floating-rate pollution control revenue bonds with various maturities. The principal amount of floating-rate pollution control revenue bonds of $1.6 billion is reflected in long-term debt on FirstEnergy’s consolidated balance sheets.

⁽³⁾

~~Includes guarantees of $300 million for OVEC obligations and $80 million for nuclear decommissioning funding assurances.~~

PricewaterhouseCoopers LLP

⁽⁴⁾

~~Includes FES’ guarantee of FGCO’s obligations under the sale and leaseback of Bruce Mansfield Unit 1.~~

Cleveland, Ohio

May 7, 2008

⁽⁵⁾

~~Includes $71 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility.~~

⁽⁶⁾

Includes approximately $194 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of its subsidiaries directly involved in these energy and energy-related transactions or financings 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 FirstEnergy’s other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related contracts is remote.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of September 30, 2007, FirstEnergy’s maximum exposure under these collateral provisions was $442 million.

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

~~FirstEnergy has guaranteed the obligations of the operators of the TEBSA project up to a maximum of~~ $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($27 million as of September 30, 2007), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. The LOC was reduced to $19 million on October 15, 2007.

6277

As described above, on July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in the Bruce Mansfield Plant Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.

~~OFF-BALANCE SHEET ARRANGEMENTS~~

FES and the Ohio Companies have obligations that are not included on FirstEnergy’s Consolidated Balance Sheets related to sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. As of September 30, 2007, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $2.0 billion.

FirstEnergy has equity ownership interests in certain businesses that are accounted for using the equity method. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations are disclosed under Guarantees and Other Assurances above.

~~MARKET RISK INFORMATION~~

~~Commodity Price Risk~~

FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. 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. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the three months and nine months ended September 30, 2007 is summarized in the following table:

Three Months Ended

Nine Months Ended

Increase (Decrease) in the Fair Value
September 30, 2007

September 30, 2007

of Commodity Derivative Contracts
Non-Hedge

Hedge

Total

Non-Hedge

Hedge

Total

(In millions)

Change in the Fair Value of

Commodity Derivative Contracts:

Outstanding net liability at beginning of period $ (845 ) $ (12 ) $ (857 ) $ (1,140 ) $ (17 ) $ (1,157 )
Additions/change in value of existing contracts (38 ) - (38 ) 69 (6 ) 63
Settled contracts 47 5 52 235 16 251
Outstanding net liability at end of period ⁽¹⁾
(836 ) (7 ) (843 ) (836 ) (7 ) (843 )

Non-commodity Net Liabilities at End of Period:

Interest rate swaps ⁽²⁾
- (8 ) (8 ) - (8 ) (8 )
Net Liabilities - Derivative Contracts
at End of Period
$ (836 ) $ (15 ) $ (851 ) $ (836 ) $ (15 ) $ (851 )

Impact of Changes in Commodity Derivative Contracts⁽³⁾

Income Statement effects (pre-tax) $ 4 $ - $ 4 $ 4 $ - $ 4
Balance Sheet effects:
Other comprehensive income (pre-tax) $ - $ 5 $ 5 $ - $ 10 $ 10
Regulatory assets (net) $ (5 ) $ - $ (5 ) $ (300 ) $ - $ (300 )

⁽¹⁾	~~Includes $836 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.~~

⁽²⁾	~~Interest rate swaps are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements below).~~

⁽³⁾	~~Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.~~

~~Derivatives are included on the Consolidated Balance Sheet as of September 30, 2007 as follows:~~

Balance Sheet Classification

Non-Hedge

Hedge

Total

(In millions)

Current-

Other assets

$
-

$
42

$
42

Other liabilities

-

(51
)
(51
)

Non-Current-

Other deferred charges

36

16

52

Other non-current liabilities

(872
)
(22
)

(894
)

Net liabilities

$
(836
)
$
(15
)
$
(851
)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of September 30, 2007 are summarized by year in the following table:

Source of Information

- Fair Value by Contract Year

2007⁽¹⁾

2008

2009

2010

2011

Thereafter

Total

(In millions)

Prices actively quoted⁽²⁾
$ - $ - $ - $ - $ - $ - $ -
Other external sources⁽³⁾
(60 ) (239 ) (173 ) (150 ) - - (622 )
Prices based on models

-

-

-

-

(114
)

(107
)

(221
)
Total⁽⁴⁾

$
(60
)
$
(239
)
$
(173
)
$
(150
)
$
(114
)
$
(107
)
$
(843
)

⁽¹⁾ ~~For the last quarter of 2007.~~

⁽²⁾ ~~Exchange traded.~~

⁽³⁾ ~~Broker quote sheets.~~

⁽⁴⁾~~Includes $836 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.~~

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of September 30, 2007. Based on derivative contracts held as of September 30, 2007, an adverse 10% change in commodity prices would decrease net income by approximately $6 million during the next 12 months.

~~Interest Rate Swap Agreements- Fair Value Hedges~~

FirstEnergy utilizes fixed-for-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk associated with its debt portfolio. 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, call options, fixed interest rates and interest payment dates match those of the underlying obligations. During the first nine months of 2007, FirstEnergy paid $8 million to terminate swaps with a notional amount ~~$150~~ ~~million as its subsidiary redeemed the associated hedged debt. The loss was recognized as interest expense during the nine-month period. As of September 30, 2007, the debt underlying the~~ ~~$600~~ ~~million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.11%, which the swaps have converted to a current weighted average variable rate of 5.72%.~~

September 30, 2007

December 31, 2006

Notional

Maturity

Fair

Notional

Maturity

Fair

Interest Rate Swaps

Amount

Date

Value

Amount

Date

Value

(In millions)

Fair value hedges $
100

2008
$
(1
)
$
100

2008
$
(2
)

50

2010

-

50

2010

(1
)

300

2013

(4
)
300

2013

(6
)

150

2015

(9
)

150

2015

(10
)

-

2025

-

50

2025

(2
)

-

2031

-

100

2031

(6
)

$
600

$
(14
)
$
750

$
(27
)

~~Forward Starting Swap Agreements - Cash Flow Hedges~~

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

		2008			2007

	(In thousands)

REVENUES:
Electric sales		$	376,028		$	339,226
Gross receipts tax collections			19,464			16,680
Total revenues			395,492			355,906

EXPENSES:
Purchased power			221,234			200,842
Other operating costs			71,077			59,461
Provision for depreciation			12,516			11,777
Amortization of regulatory assets			16,346			15,394
Deferral of new regulatory assets			(3,526	)		(17,088	)
General taxes			21,855			19,851
Total expenses			339,502			290,237

OPERATING INCOME			55,990			65,669

OTHER INCOME (EXPENSE):
Miscellaneous income (expense)			(191	)		1,417
Interest expense			(15,322	)		(11,337	)
Capitalized interest			(806	)		258
Total other expense			(16,319	)		(9,662	)

INCOME BEFORE INCOME TAXES			39,671			56,007

INCOME TAXES			18,279			24,263

NET INCOME			21,392			31,744

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits			(3,473	)		(2,825	)
Unrealized gain on derivative hedges			16			16
Change in unrealized gain on available-for-sale securities			11			(3	)
Other comprehensive loss			(3,446	)		(2,812	)
Income tax benefit related to other comprehensive loss			(1,506	)		(1,298	)
Other comprehensive loss, net of tax			(1,940	)		(1,514	)

TOTAL COMPREHENSIVE INCOME		$	19,452		$	30,230

The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company
are an integral part of these statements.

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,		December 31,
	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	43	$	46
Receivables-
Customers (less accumulated provisions of $4,201,000 and $3,905,000,
respectively, for uncollectible accounts)		141,316		137,455
Associated companies		23,396		22,014
Other		28,833		19,529
Notes receivable from associated companies		16,923		16,313
Prepaid gross receipts taxes		41,242		-
Other		2,426		3,077
		254,179		198,434
UTILITY PLANT:
In service		2,230,667		2,219,002
Less - Accumulated provision for depreciation		843,500		838,621
		1,387,167		1,380,381
Construction work in progress		33,727		24,251
		1,420,894		1,404,632
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		132,152		137,859
Non-utility generation trusts		113,958		112,670
Other		536		531
		246,646		251,060
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		777,616		777,904
Pension assets		69,405		66,111
Other		29,770		33,893
		876,791		877,908
	$	2,798,510	$	2,732,034
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Short-term borrowings-
Associated companies	$	183,102	$	214,893
Other		150,000		-
Accounts payable-
Associated companies		61,476		83,359
Other		50,516		51,777
Accrued taxes		9,302		15,111
Accrued interest		13,677		13,167
Other		23,330		25,311
		491,403		403,618
CAPITALIZATION:
Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
4,427,577 shares outstanding		88,552		88,552
Other paid-in capital		920,265		920,616
Accumulated other comprehensive income		3,006		4,946
Retained earnings		79,336		57,943
Total common stockholder's equity		1,091,159		1,072,057
Long-term debt and other long-term obligations		732,465		777,243
		1,823,624		1,849,300
NONCURRENT LIABILITIES:
Regulatory liabilities		67,347		73,559
Accumulated deferred income taxes		220,500		210,776
Retirement benefits		41,644		41,298
Asset retirement obligations		83,129		81,849
Other		70,863		71,634
		483,483		479,116
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	2,798,510	$	2,732,034

The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
integral part of these balance sheets.

FirstEnergy utilizes forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 2007 and 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. During the first nine months of 2007, FirstEnergy terminated forward swaps with an aggregate notional value of $1.6 billion. FirstEnergy paid $20 million in cash related to the terminations, which will be recognized over the terms of the associated future debt. There was no ineffective portion associated with the loss. As of September 30, 2007, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $400 million and an aggregate fair value of $5 million.

September 30, 2007

December 31, 2006

Notional

Maturity

Fair

Notional

Maturity

Fair

Forward Starting Swaps

Amount

Date

Value

Amount

Date

Value

(In millions)

Cash flow hedges $
25

2015
$
-
$
25

2015
$
-

300

2017

5

200

2017

(4
)

25

2018

(1
)
25

2018

(1
)

50

2020

1

50

2020

1

$
400

$
5

$
300

$
(4
)

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2008			2007
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	21,392		$	31,744
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		12,516			11,777
Amortization of regulatory assets		16,346			15,394
Deferral of new regulatory assets		(3,526	)		(17,088	)
Deferred costs recoverable as regulatory assets		(8,403	)		(18,433	)
Deferred income taxes and investment tax credits, net		10,541			13,366
Accrued compensation and retirement benefits		(10,488	)		(8,786	)
Cash collateral		301			1,450
Pension trust contribution		-			(13,436	)
Increase in operating assets-
Receivables		(13,701	)		(30,050	)
Prepayments and other current assets		(40,591	)		(36,225	)
Increase (Decrease) in operating liabilities-
Accounts payable		(23,144	)		(46,168	)
Accrued taxes		(5,809	)		(9,152	)
Accrued interest		510			5,518
Other		4,991			3,920
Net cash used for operating activities		(39,065	)		(96,169	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		118,209			119,361
Redemptions and Repayments
Long-term debt		(45,112	)		-
Net cash provided from financing activities		73,097			119,361

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(28,902	)		(20,404	)
Sales of investment securities held in trusts		24,407			12,758
Purchases of investment securities held in trusts		(29,083	)		(15,509	)
Loan repayments from (loans to) associated companies, net		(610	)		708
Other		153			(747	)
Net cash used for investing activities		(34,035	)		(23,194	)

Net change in cash and cash equivalents		(3	)		(2	)
Cash and cash equivalents at beginning of period		46			44
Cash and cash equivalents at end of period	$	43		$	42

The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are
an integral part of these statements.

~~Equity Price Risk~~

COMBINED MANAGEMENT’S DISCUSSION

AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain disclosures referenced in Management’s Narrative Analysis of Results of Operations of FES and the Companies. This information should be read in conjunction with (i) FES’ and the Companies’ respective Consolidated Financial Statements and Management’s Narrative Analysis of Results of Operations; (ii) the Combined Notes to Consolidated Financial Statements as they relate to FES and the Companies; and (iii) FES’ and the Companies’ respective 2007 Annual Reports on Form 10-K.

~~Included in nuclear decommissioning trusts are marketable equity securities carried at their market value~~Regulatory Matters (Applicable to each of ~~approximately $1.4 billion as of September 30, 2007 and December 31, 2006. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a~~ ~~$139~~ ~~million reduction in fair value as of September 30, 2007.~~

~~CREDIT RISK~~

~~Credit risk is~~ the risk of an obligor’s failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB+ (S&P). As of September 30, 2007, the largest credit concentration with one party (currently rated investment grade) represented 10.9% of FirstEnergy‘s total credit risk. Within FirstEnergy’s unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserves, were with investment-grade counterparties as of September 30, 2007.

~~Outlook~~

~~State Regulatory Matters~~Companies)

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

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

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


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

·	continuing regulation of the Companies' transmission and distribution systems; and

·	requiring corporate separation of regulated and unregulated business activities.

The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately ~~$227~~$137 million as of ~~September 30, 2007~~March 31, 2008 (JCP&L - ~~$93~~$78 million and Met-Ed - ~~$43 million and Penelec - $91~~$59 million). Regulatory assets not earning a current return ~~will~~are expected to be recovered by 2014 for JCP&L and by 2020 for ~~Met-Ed and Penelec.~~Met-Ed. The following table discloses regulatory assets by company:

	September 30,		December 31,		Increase			March 31,		December 31,		Increase
Regulatory Assets*	2007		2006		(Decrease)			2008		2007		(Decrease)
	*(In millions)*							(In millions)
OE	$	717	$	741	$	(24	)	$	710	$	737	$	(27	)
CEI		856		855		1			854		871		(17	)
TE		215		248		(33	)		188		204		(16	)
JCP&L		1,758		2,152		(394	)		1,476		1,596		(120	)
Met-Ed		459		409		50			530		495		35
ATSI		42		36		6			39		42		(3	)
Total	$	4,047	$	4,441	$	(394	)	$	3,797	$	3,945	$	(148	)

Penelec had net regulatory liabilities of approximately ~~$77~~$67 million

and ~~$96~~$74 million as of ~~September 30, 2007~~March 31, 2008 and December 31,

~~2006,~~ 2007, respectively. These net regulatory liabilities are included in

Other Non-current Liabilities on the Consolidated Balance Sheets.

~~Regulatory assets by source are as follows:~~

September 30,

December 31,

Increase

Regulatory Assets By Source

2007

2006

(Decrease)

(In millions)

Regulatory transition costs $ 2,583 $ 3,266 $ (683 )
Customer shopping incentives 537 603 (66 )
Customer receivables for future income taxes 257 217 40
Societal benefits charge (11 ) 11 (22 )
Loss on reacquired debt 58 43 15
Employee postretirement benefits 41 47 (6 )
Nuclear decommissioning, decontamination
and spent fuel disposal costs (118 ) (145 ) 27
Asset removal costs (177 ) (168 ) (9 )
Property losses and unrecovered plant costs 11 19 (8 )
MISO/PJM transmission costs 309 213 96
Fuel costs - RCP 175 113 62
Distribution costs - RCP 298 155 143
Other

84

67

17

Total
$
4,047

$
4,441

$
(394
)

~~Reliability Initiatives~~Ohio

~~In late 2003~~(Applicable to OE, CEI 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.

~~Ohio~~TE)

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.~~RCP. 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. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period ~~2007~~2008 through 2010:

Amortization

Total

Period

OE

CEI

TE

Ohio

(In millions)

2007
$
176
$
108
$
92
$
376
2008 209 126 113 448
2009 - 217 - 217
2010

-

269

-

269

Total Amortization

$
385

$
720

$
205

$
1,310

Amortization							Total
Period	OE		CEI		TE		Ohio
	(In millions)
2008	$	204	$	126	$	118	$	448
2009		-		212		-		212
2010		-		273		-		273
Total Amortization	$	204	$	611	$	118	$	933

~~Several parties subsequently filed appeals to the Supreme Court of Ohio in connection with certain portions of the RCP approved by the PUCO. In its order,~~On January 4, 2006, the PUCO ~~authorized~~issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel ~~costs, all such~~ costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a ~~25-year~~twenty-five-year period through distribution rates, which was expected to begin on January 1, 2009 for OE and TE, and approximately May 2009 for CEI. Through September 30, 2007, the deferred fuel costs, including interest, were $89 million, $61 million and $26 million for OE, CEI and TE, respectively.

rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated ~~certain provisions~~a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” ~~because fuel costs are a component of generation service, not distribution service,~~ and ~~because the Court concluded the PUCO did not address whether the deferral of fuel costs was anticompetitive. The Court~~ remanded the matter to the PUCO for further consideration consistent with the Court’s Opinion on this issue and affirmed the PUCO’s Order in all other respects. On September 7, 2007, the Ohio Companies filed a Motion for Reconsideration with the Court.consideration. On September 10, 2007 the Ohio Companies filed an ~~Application~~application with the PUCO that ~~requests~~requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. ~~The~~On January 9, 2008 the PUCO approved the Ohio ~~Companies requested the riders become effective~~Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in ~~October 2007 and end in~~2008 commencing January 1, 2008 through December 31, 2008, ~~subject to reconciliation~~ which is expected to ~~continue through~~be approximately $189 million (OE - $91 million, CEI - $72 million and TE - $26 million). In addition, the ~~first quarter~~PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million (OE - $114 million, CEI - $79 million and TE - $33 million) of ~~2009.~~deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider, with alternative options for the recovery period ranging from five to twenty-five years. This ~~matter~~second application is currently pending before the PUCO. Although unable to predict the ultimate outcome of this matter, the Ohio Companies intend to continue deferring the fuel costs pursuant to the RCP, pending the Court’s disposition of the MotionPUCO and a hearing has been set for ~~Reconsideration and the PUCO’s action with respect to the Ohio Companies’ Application.~~July 15, 2008.

~~On May 8, 2007, the~~ Ohio Companies filed ~~with the PUCO a notice of intent to file~~an application and rate request for an increase in electric distribution ~~rates. The Ohio Companies filed the application and rate request~~rates with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the average electric bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in ~~operating~~operation and maintenance expenses and recovery of regulatory assets ~~created by deferrals~~ that were ~~approved~~authorized in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million (OE - $156 million, CEI - $108 million and TE - $68 million). On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of their investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million (OE - $57 million to $66 million, CEI - $54 million to $61 million and TE - $50 million to $53 million), with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. This amount excludes the recovery of deferred fuel costs, whose recovery is now being sought in a separate proceeding before the PUCO, discussed above. On January 3, 2008, the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings, the PUCO Staff submitted testimony decreasing their recommended revenue increase to ~~establish~~a range of $114 million to $132 million. Additionally, in testimony submitted on February 11, 2008, the ~~test period data~~PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, ~~will be used as~~if upheld by the ~~basis for setting rates~~PUCO, would result in ~~that proceeding.~~the write-off of approximately $45 million (OE - $31 million, CEI - $9 million and TE - $5 million) of interest costs deferred through March 31, 2008 ($0.09 per share of common stock). The PUCO ~~Staff~~ is expected to ~~issue~~render its ~~report in~~decision during the ~~case in the fourth quarter of 2007 with evidentiary hearings to follow in early 2008. The PUCO order is expected to be issued in the~~ second or third quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing retail generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per ~~kilowatt-hour~~KWH would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. A slice-of-system approach would require the successful bidder to be responsible for supplying a fixed percentage of the utility’s total load notwithstanding the customer’s classification. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. ~~Comments by intervenors in the case were filed on September 5, 2007. The PUCO Staff filed comments on September 21, 2007. Parties filed~~Initial and reply comments on the proposal were filed by various parties in September and October ~~12, 2007.~~2007, respectively. The ~~Ohio Companies requested that~~proposal is currently pending before the ~~PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process.~~PUCO.

On ~~September 25, 2007,~~April 22, 2008, an amended version of Substitute SB221 was passed by the Ohio ~~Governor’s proposed~~House of Representatives and sent back to the Ohio Senate for concurrence. On April 23, 2008, the Ohio Senate approved the House's amendments to Substitute SB221 and forwarded the bill to the Governor for signature, which he signed on May 1, 2008. Amended Substitute SB221 requires all electric distribution utilities to file an RSP, now called an ESP, with the PUCO. An ESP is required to contain a proposal for the supply and pricing of retail generation and may include proposals, without limitation, related to one or more of the following:

·	automatic recovery of prudently incurred fuel, purchased power, emission allowance costs and federally mandated energy taxes;

·	construction work in progress for costs of constructing an electric generating facility or environmental expenditure for any electric generating facility;

·	costs of an electric generating facility;

·	terms related to customer shopping, bypassability, standby, back-up and default service;

·	accounting for deferrals related to stabilizing retail electric service;

·	automatic increases or decreases in standard service offer price;

·	phase-in and securitization;

·	transmission service and related costs;

·	distribution service and related costs; and

·	economic development and energy efficiency.

A utility could also simultaneously file an MRO in which it would have to demonstrate the following objective market criteria: The utility or its transmission service affiliate belongs to a FERC-approved RTO having a market-monitor function and the ability to mitigate market power, and a published source exists that identifies information for traded electricity and energy ~~plan was officially introduced~~products that are contracted for delivery two years into the ~~Ohio Senate.~~future. The PUCO would test the ESP and its pricing and all other terms and conditions against the MRO and may only approve the ESP if it is found to be more favorable to customers. As part of an ESP with a plan period longer than three years, the PUCO shall prospectively determine every fourth year of the plan whether it is substantially likely the plan will provide the electric distribution utility a return on common equity significantly in excess of the return likely to be earned by publicly traded companies, including utilities, that face comparable business and financial risk (comparable companies). If so, the PUCO may terminate the ESP. Annually under an ESP, the PUCO shall determine whether an electric distribution utility's earned return on common equity is significantly in excess of returns earned on common equity during the same period by comparable companies, and if so, shall require the utility to return such excess to customers by prospective adjustments. Amended Substitute SB221 also includes provisions dealing with advanced and renewable energy standards that contemplate 25% of electrical usage from these sources by 2025. Energy efficiency measures in the bill ~~proposes~~require energy savings in excess of 22% by 2025. Requirements are in place to ~~revise state~~meet annual benchmarks for renewable energy ~~policy to address electric generation pricing after 2008, establish advanced energy portfolio standards~~resources and energy efficiency, ~~standards,~~subject to review by the PUCO. FirstEnergy is currently evaluating this legislation and ~~create GHG emissions reporting and carbon control planning requirements. The bill also proposes~~expects to ~~move to a “hybrid” system for determining rates for PLR service~~file an ESP in ~~which electric utilities would provide regulated generation service unless they satisfy a statutory burden to demonstrate~~ the ~~existence~~second or third quarter of a competitive market for retail electricity. The Senate Energy & Public Utilities Committee has been conducting hearings on the bill and receiving testimony from interested parties, including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer groups, utility executives and others. Several proposed amendments to the bill have been submitted, including those from Ohio’s investor-owned electric utilities. A substitute version of the bill, which incorporated certain of the proposed amendments, was introduced into the Senate Energy & Public Utilities Committee on October 25, 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of the Ohio Companies.2008.

Pennsylvania(Applicable to FES, Met-Ed, Penelec, OE and Penn)

Met-Ed and Penelec ~~have been purchasing~~purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement and various amendments. 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.agreement. 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 requirements during the term of these agreements with FES.

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 were substantially higher than the fixed price in the partial requirements agreements.~~

Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy ~~thus~~ sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The parties also have separately terminated the supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the ~~restated~~ agreement is expected to remain below wholesale market prices during the term of the agreement.

If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for ~~its~~their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.

Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec ~~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. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

The PPUC entered its ~~Opinion~~opinion and ~~Order~~order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, ~~when new transmission rates were effective,~~ 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 into 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 transmission deferral.~~costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC 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 of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part the MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. OnFrom June ~~19,~~through October 2007, initial responsive and reply briefs were filed ~~and responsive briefs were filed through September 21, 2007. Reply briefs were filed on October 5, 2007.~~by various parties. Oral arguments are ~~expected~~scheduled to take place in ~~late 2007 or early~~September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the ~~financial condition and~~ results of operations of Met-Ed, Penelec and FirstEnergy.

As of September 30, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $496 million and $58 million, respectively. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On ~~August 18, 2006, a PPUC Order was entered requiring~~April 14, 2008, Met-Ed and Penelec filed annual updates to ~~reflect~~ the ~~deferred NUG cost balances as if~~TSC rider for the ~~stranded cost accounting methodology modification had not been implemented. As~~period June 1, 2008, through May 31, 2009. The proposed TSCs include a ~~result~~component for under-recovery of ~~this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3~~actual transmission costs incurred during the prior period (Met-Ed - $144 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~~- $4 million) and future transmission cost ~~accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order~~projections for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in February 2007 and briefing was completed on March 28, 2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.

~~On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from~~ June 2008 through May ~~2011. The filing proposes multiple, competitive RFPs with staggered delivery periods~~2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed has proposed a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for ~~fixed-price, tranche-based, pay as bid PLR supply to~~recovery through future TSCs by December 31, 2010.

On March 13, 2008, the PPUC approved the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service will be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. On September 28, 2007, Penn filed aprocurement process in Penn’s Joint Petition for ~~Settlement resolving all but one issue~~Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the ~~case. Briefs~~two RFPs for small commercial load were ~~also~~approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed ~~on September 28, 2007~~compliance tariffs with the new default service generation rates based on the ~~unresolved issue~~approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. On April 14, 2008, the first RFP for residential customers’ load was held consisting of ~~incremental uncollectible accounts expense.~~tranches for both 12 and 24-month supply. The ~~settlement~~PPUC approved the bids on April 16, 2008. The second RFP is ~~either supported, or not opposed, by all parties. The~~scheduled to be held on May 14, 2008, after which time the PPUC is expected to ~~act on~~approve the ~~settlement and the unresolved issue in late November or early December 2007 for the initial RFP~~new rates to ~~take place in January~~go into effect June 1, 2008.

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet ~~demand~~energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and ~~an optional~~a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy. The final form of ~~any~~this pending legislation ~~arising from the special legislative session~~ is uncertain. Consequently, ~~FirstEnergy is~~Met-Ed, Penelec, OE and Penn are unable to predict what impact, if any, such legislation may have on ~~its~~their operations.

New Jersey(Applicable to JCP&L)

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of ~~September 30, 2007,~~March 31, 2008, the accumulated deferred cost balance totaled approximately ~~$330~~$264 million.

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

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that ~~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~~The NJBPU Staff circulated a revised ~~draft~~drafts of the proposal to interested ~~stakeholders. Another revised draft was circulated by~~stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU ~~Staff~~accepted proposed rules for publication in the New Jersey Register on ~~February 8, 2007.~~March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 with comments from interested parties due on May 16, 2008.

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated ~~with~~through the ~~issuance~~creation 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 New Jersey’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;~~

·	~~Maintain unit prices for electricity to 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 obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing (1) energy efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing issues have completed their assigned tasks of data gathering and analysis and have provided reports to the EMP Committee. PublicIn addition, public stakeholder meetings were held in the fall of 2006 and in early ~~2007, and further~~2007.

On April 17, 2008, a draft EMP was released for public ~~meetings are expected later in 2007. A final~~comment. The draft EMP establishes four major goals:

·	maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020;

·	reduce peak demand for electricity by 5,700 MW by 2020 (amounting to about a 22% reduction in projected demand);

·	meet 22.5% of the state’s electricity needs with renewable energy by 2020; and

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

Following the ~~EMP~~public comment period which is expected to extend into July 2008, a final EMP will be ~~presented~~issued to ~~the Governor in late 2007.~~be followed by appropriate legislation and regulation as necessary. At this time, ~~FirstEnergy~~JCP&L cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its ~~operations or those of JCP&L.~~operations.

On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments ~~which~~that were ~~due on~~submitted in September ~~26,~~and October 2007. ~~At this time, FirstEnergy cannot predict~~Final regulations (effective upon publication) were published in the ~~outcome~~New Jersey Register March 17, 2008. Upon preliminary review of ~~this process nor determine~~ the ~~impact, if any, such~~new regulations, ~~may have~~JCP&L does not expect a material impact on its ~~operations or those of JCP&L.~~operations.

FERC Matters(Applicable to FES and each of the Companies)

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the ~~RTOR~~through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate so-called “pancaking” of transmission charges 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~~rate mechanism to recover lost ~~RTOR~~transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition ~~period from load serving entities.~~period. 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 MISO, PJM, and 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 the ~~fourth~~second quarter of ~~2007.~~2008.

PJM Transmission Rate Design

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, BG&E and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. Hearings were held and numerous parties appeared and litigated various ~~issues; including~~issues concerning PJM rate design; notably AEP, which ~~filed in opposition proposing~~proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across ~~PJM. At~~PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the ~~conclusion~~effect of shifting recovery of the ~~hearings, the ALJ issued an initial decision adopting the FERC Trial Staff’s position that the cost~~costs of ~~all PJM~~high voltage 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. Numerous parties,~~lines to other transmission zones, including ~~FirstEnergy, submitted briefs opposing the ALJ’s decision~~those where JCP&L, Met-Ed, and ~~recommendations.~~Penelec serve load. On April 19, 2007, the FERC issued an order ~~rejecting the ALJ’s findings and recommendations in nearly every respect. The FERC found~~finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be ~~socialized~~collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. ~~Nevertheless, the~~The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 ~~Order. Subsequently, FirstEnergy and other parties filed pleadings opposing~~order. On January 31, 2008, the requests for ~~rehearing.~~rehearing were denied. The FERC’s ~~Orders~~orders on PJM rate design ~~if sustained on rehearing and appeal,~~ will prevent the allocation of a portion of the ~~cost~~revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission ~~costs shifting to~~revenue recovery from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge. The FERC’s action on the settlement agreement is pending. The remaining merchant transmission cost allocation issues will proceed to hearing in May 2008. On February 13, 2008, AEP appealed the FERC’s orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.

~~New FERC Transmission~~Post Transition Period Rate Design ~~Filings~~

The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within the MISO, and between MISO and PJM. On August 1, 2007, ~~a number of~~ filings were made ~~with~~by MISO, PJM, and the ~~FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.~~

~~FirstEnergy joined in a filing made by the MISO~~vast majority of transmission owners, ~~that would maintain~~including FirstEnergy affiliates, which proposed to retain the existing ~~“license plate” rates for~~ transmission service within MISO provided over existing transmission facilities. FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to continue the elimination of transmission rates associated with service over existing transmission facilities between MISO and PJM. If adoptedrate design. These filings were approved by the FERC ~~these filings would not affect~~on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving ~~FirstEnergy~~ affiliates for transmission service over existing transmission ~~facilities.~~facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint ~~be maintained~~ (known as the RECB ~~Process). Each of these filings was supported by the majority of transmission owners in either MISO or PJM, as applicable.~~

~~The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV and higher transmission facilities~~methodology) be spread throughout the entire MISO footprint. Further, Indianapolis Power and Light Company separately moved the FERC to reopen the record to address the cost allocation for the RECB Process. If either proposal is adopted by the FERC, it could shift a greater portion of the cost of new 345 kV and higher transmission facilities to the FirstEnergy footprint in MISO, and increase the transmission rates paid by load-serving FirstEnergy affiliates in MISO.retained.

Distribution of ~~this proposal, if adopted by FERC, would be to shift significant costs to~~MISO Network Service Revenues

Effective February 1, 2008, the ~~FirstEnergy zones~~MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and ~~PJM. FirstEnergy believes that most~~a majority of ~~these costs would ultimately be recoverable in retail rates. On October 12, 2007, BG&E filed a motion to dismiss AEP’s complaint. On October 16, 2007,~~ the ~~Organization of~~ MISO States filed comments urging the FERC to dismiss AEP’s complaint. Interventions and protests to AEP’s complaint and answers to BG&E’s motion to dismiss were due October 29, 2007. FirstEnergy and other transmission owners filed ~~protests~~on December 3, 2007 to ~~AEP’s complaint~~change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation. This clarification was necessary because some network transmission service revenues are collected and ~~support for BG&E’s motion to dismiss. AEP has asked for consolidation of its complaint~~retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the ~~cases above,~~FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and ~~FirstEnergy expects it~~that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.

Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be ~~resolved~~charged by MISO for network service. On February 2, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.

On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same ~~timeline as those cases.~~day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. This matter is currently pending before the FERC.

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

MISO made a filing on September 14, 2007 to establish ~~Ancillary Services markets~~an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. ~~An effective date of June 1, 2008 was requested~~This filing would permit load serving entities to purchase their operating reserve requirements in ~~the filing.~~

MISO’s previous filing to establish an Ancillary Services market was rejected without prejudice by FERC on June 22, 2007, subject to MISO making certain modifications in its filing. FirstEnergy believes that MISO’s September 14 filing generally addresses the FERC’s directives. FirstEnergy supportsa competitive market. FES, CEI, OE, Penn and TE support the proposal to establish markets for Ancillary Services and consolidate existing balancing ~~areas,~~areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. MISO has since notified the FERC that the start of its ASM is delayed until September of 2008.

Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join the MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but ~~filed objections on specific~~covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.

On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne to pay the PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FES and the Companies and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed the MISO ~~proposal. Interventions~~to submit detailed plans to integrate Duquesne into the MISO. Finally, the FERC directed MISO and ~~protests~~PJM to ~~MISO’s filing were made~~work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into the MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 9, 2008.

On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators can contract with ~~FERC~~PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfies the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on ~~October 15, 2007.~~April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. FirstEnergy is participating in the May 2008 RPM auction for the 2011-2012 RPM delivery year.

MISO Resource Adequacy Proposal

~~Order No. 890~~MISO made a filing on ~~Open Access Transmission Tariffs~~December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load serving entities in its state. FirstEnergy generally supports the proposal as it promotes a mechanism that will result in long-term commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC approved MISO’s Resource Adequacy proposal on March 26, 2008. Rehearing requests are pending on the FERC’s March 26 Order. A compliance filing establishing the enforcement mechanism for the reserve margin requirement is due on or before June 25, 2008.

Organized Wholesale Power Markets

On February ~~16, 2007,~~21, 2008, the FERC issued a ~~final~~NOPR through which it proposes to adopt new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule ~~(Order No. 890)~~addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FES and the Companies do not believe that ~~revises its decade-old open access transmission~~the proposed rule will have a significant impact on their operations. Comments on the NOPR were filed on April 18, 2008.

Environmental Matters

Various federal, state and local authorities regulate FES and the Companies with regard to air and water quality and other environmental matters. The effects of compliance on FES and the Companies with regard to environmental matters could have a material adverse effect on their earnings and competitive position to the extent that they compete with companies that are not subject to such regulations and, ~~policies. The FERC explained that~~therefore, do not bear 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 became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffsrisk of costs associated with compliance, or failure to comply, with such regulations. FES and the ~~FERC’s order. MISO, PJM and ATSI submitted tariff filings to~~Companies estimate capital expenditures for environmental compliance of approximately $1.4 billion for the ~~FERC on October 11, 2007. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.~~period 2008-2012.

~~Environmental Matters~~

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

Clean Air Act Compliance(Applicable to FES)

~~FirstEnergy~~FES is required to meet federally-approved SO₂ emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO₂ regulations in Ohio that allows for compliance based on a 30-day averaging period. ~~FirstEnergy~~FES 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~~CAA. FES has disputed those alleged violations based on its ~~Clean Air Act~~CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.

~~FirstEnergy~~FES complies with SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. 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~~FES' 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~~FES believes its facilities are also complying with the NO_X budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

National Ambient Air Quality Standards(Applicable to FES)

~~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 ~~allowed each affected state until 2006 to develop implementing regulations to achieve additional~~requires reductions of NO_X and SO₂ emissions in two phases (Phase I in 2009 for NO_X, 2010 for SO₂ and Phase II in 2015 for both NO_X and SO₂). ~~FirstEnergy's~~FES' Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO₂ and NO_X ~~emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on NO~~_X emissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. 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. CAIR has been challenged in the United States Court of Appeals for the District of Columbia. The future cost of compliance with these regulations may be substantial and ~~will~~may depend on the outcome of this litigation and how ~~they are~~CAIR is ultimately ~~implemented by the states in which FirstEnergy operates affected facilities.~~implemented.

Mercury Emissions(Applicable to FES)

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. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, ~~FirstEnergy’s~~FES’ only Pennsylvania coal-fired ~~Pennsylvania~~ power plant, until 2015, if at all.

W. H. Sammis Plant(Applicable to FES, OE and Penn)

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NO_X and SO₂ emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. 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~~FGCO, OE and Penn could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation ~~settlement agreement~~consent decree are currently estimated to be ~~$1.7~~$1.3 billion for ~~2007 through 2011~~FGCO for 2008-2012 ($~~400~~650 million of which is expected to be spent during ~~2007,~~2008, with the largest portion of the remaining ~~$1.3 billion~~$650 million expected to be spent in ~~2008 and~~ 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

Climate Change(Applicable to FES)

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

Clean Water Act(Applicable to FES)

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to ~~FirstEnergy's~~FES’ plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to ~~FirstEnergy's~~FES' 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~~(when aquatic organisms are pinned against screens or other parts of a cooling water intake ~~system,~~system) and entrainment ~~which~~(which occurs when aquatic life is drawn into a facility's cooling water ~~system.~~system). On January 26, 2007, the ~~federal~~United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review certain aspects of the Second Circuit’s decision. FirstEnergy is ~~evaluating~~studying various control options and their costs and effectiveness. Depending on the ~~outcome~~results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future ~~cost~~costs of compliance with these standards may require material capital expenditures.

Regulation of Hazardous Waste(Applicable to FES and each of the Companies)

Under NRC regulations, ~~FirstEnergy~~FES and the Companies must ensure that adequate funds will be available to decommission its nuclear facilities. As of ~~September 30, 2007, FirstEnergy~~March 31, 2008, FES and the Companies had approximately ~~$1.5~~$2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and ~~Perry.~~TMI-2. As part of the application to the NRC to transfer the ownership of ~~these nuclear facilities~~Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” 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~~and FES (and Exelon for TMI-1 as it relates to ~~seek~~the timing of the decommissioning of TMI-2) seeks 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~~may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of ~~September 30, 2007,~~March 31, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. ~~In addition,~~Total liabilities of approximately $92 million (JCP&L - $65 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through March 31, 2008. Included in the total for JCP&L ~~has~~are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants in New Jersey; ~~those costs~~which are being recovered by JCP&L through a non-bypassable SBC. ~~Total liabilities of approximately $89 million have been accrued through September 30, 2007.~~

Other Legal Proceedings

~~Other Legal Proceedings~~

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

Power Outages and Related Litigation(Applicable to JCP&L)

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior ~~Court. FirstEnergy~~Court and a case management conference with the presiding Judge is scheduled for June 13, 2008. JCP&L is defending this class action but is unable to predict the outcome of this matter. No liability has been accrued as of ~~September 30, 2007.~~

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FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those 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. Two 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 cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and AEP, as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. 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. The four cases remaining were consolidated for hearing by the PUCO in an order dated March 7, 2006. In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled 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 January 8, 2008.

Nuclear Plant Matters(Applicable to FES)

Other Legal Matters(Applicable to OE, JCP&L and FES)

~~NEW ACCOUNTING STANDARDS AND INTERPRETATIONS~~

~~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.

~~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. This Statement 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~~and SFAS 107~~. 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.

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

~~FSP FIN 39-1 – “Amendment of FASB Interpretation No. 39”~~

8093

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2007

2006

2007
2006

(In thousands)

REVENUES:

Electric sales to affiliates $ 805,372 $ 762,106 $ 2,209,743 $ 1,997,096
Other 365,536 347,474 1,048,189 1,063,026
Total revenues 1,170,908 1,109,580 3,257,932 3,060,122

EXPENSES:

Fuel 301,786 315,521 804,201 844,913
Purchased power from non-affiliates 228,755 173,620 577,831 477,249
Purchased power from affiliates 62,508 55,647 209,576 188,698
Other operating expenses 235,033 198,716 731,774 774,767
Provision for depreciation 48,500 46,894 145,030 135,414
General taxes 22,242 17,609 64,870 55,550
Total expenses 898,824 808,007 2,533,282 2,476,591

OPERATING INCOME
272,084 301,573 724,650 583,531

OTHER INCOME (EXPENSE):

Miscellaneous income 12,655 27,662 47,756 44,843
Interest expense to affiliates (9,641 ) (41,416 ) (61,904 ) (122,664 )
Interest expense - other (31,794 ) (7,914 ) (70,845 ) (17,880 )
Capitalized interest 5,131 2,389 12,763 8,698
Total other expense (23,649 ) (19,279 ) (72,230 ) (87,003 )

INCOME BEFORE INCOME TAXES
248,435 282,294 652,420 496,528

INCOME TAXES
93,671 106,175 243,736 184,572

NET INCOME
154,764 176,119 408,684 311,956

OTHER COMPREHENSIVE INCOME (LOSS):

Pension and other postretirement benefits (1,360 ) - (4,080 ) -
Unrealized gain (loss) on derivative hedges 4,863 (6,257 ) 9,451 (6,376 )
Change in unrealized gain on available for sale securities 21,263 20,945 80,053 29,266
Other comprehensive income 24,766 14,688 85,424 22,890
Income tax expense related to other
  comprehensive income 8,915 5,453 30,474 8,548
Other comprehensive income, net of tax 15,851 9,235 54,950 14,342

TOTAL COMPREHENSIVE INCOME
$ 170,615 $ 185,354 $ 463,634 $ 326,298

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part of
these statements.

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

September 30,

December 31,

2007

2006

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 2 $ 2
Receivables-
Customers (less accumulated provisions of $8,007,000 and $7,938,000,
respectively, for uncollectible accounts) 144,443 129,843
Associated companies 285,462 235,532
Other (less accumulated provisions of $9,000 and $5,593,000,
respectively, for uncollectible accounts) 5,416 4,085
Notes receivable from associated companies 242,612 752,919
Materials and supplies, at average cost 441,066 460,239
Prepayments and other 83,825 57,546
1,202,826 1,640,166
PROPERTY, PLANT AND EQUIPMENT:

In service 8,183,578 8,355,344
Less - Accumulated provision for depreciation 3,852,896 3,818,268
4,330,682 4,537,076
Construction work in progress 596,879 339,886
4,927,561 4,876,962
OTHER PROPERTY AND INVESTMENTS:

Nuclear plant decommissioning trusts 1,342,083 1,238,272
Long-term notes receivable from associated companies 62,900 62,900
Other 39,964 72,509
1,444,947 1,373,681
DEFERRED CHARGES AND OTHER ASSETS:

Accumulated deferred income taxes 240,182 -
Goodwill 24,248 24,248
Property taxes 44,111 44,111
Pension assets 9,449 -
Other 70,638 39,839
388,628 108,198
$ 7,963,962 $ 7,999,007
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ 1,469,721 $ 1,469,660
Short-term borrowings-
Associated companies 237,070 1,022,197
Accounts payable-
Associated companies 432,695 556,049
Other 177,820 136,631
Accrued taxes 537,060 113,231
Other 163,239 100,941
3,017,605 3,398,709
CAPITALIZATION:

Common stockholder's equity-
Common stock, without par value, authorized 750 shares-
7 and 8 shares outstanding, respectively 1,163,934 1,050,302
Accumulated other comprehensive income 166,673 111,723
Retained earnings 1,038,412 697,338
Total common stockholder's equity 2,369,019 1,859,363
Long-term debt 505,196 1,614,222
2,874,215 3,473,585
NONCURRENT LIABILITIES:

Deferred gain on sale and leaseback transaction 1,068,769 -
Accumulated deferred income taxes - 121,449
Accumulated deferred investment tax credits 62,275 65,751
Asset retirement obligation 797,357 760,228
Retirement benefits 53,505 103,027
Property taxes 44,433 44,433
Other 45,803 31,825
2,072,142 1,126,713
COMMITMENTS AND CONTINGENCIES (Note 10)

$ 7,963,962 $ 7,999,007

The preceding Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral part of these
balance sheets.

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended

September 30,

2007

2006

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 408,684 $ 311,956
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 145,030 135,414
Nuclear fuel and lease amortization 75,102 66,360
Deferred income taxes and investment tax credits, net (381,042 ) 47,188
Investment impairment 14,296 -
Accrued compensation and retirement benefits 3,414 13,704
Commodity derivative transactions, net 4,913 46,500
Gain on asset sales (12,105 ) (35,973 )
Cash collateral, net (19,798 ) 20,643
Pension trust contribution (64,020 ) -
Decrease (increase) in operating assets:
Receivables (30,172 ) (46,063 )
Materials and supplies 48,123 (1,683 )
Prepayments and other current assets (5,118 ) 211
Increase (decrease) in operating liabilities:
Accounts payable (108,949 ) (162,502 )
Accrued taxes 424,100 77,524
Accrued interest 14,355 2,431
Other (36,498 ) (17,605 )
Net cash provided from operating activities 480,315 458,105

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt - 251,945
Equity contributions from parent 710,468 -
Short-term borrowings, net - 66,817
Redemptions and Repayments-
Common stock (600,000 ) -
Long-term debt (1,110,174 ) (253,240 )
Short-term borrowings, net (785,127 ) -
Common stock dividend payments (67,000 ) -
Net cash provided from (used for) financing activities (1,851,833 ) 65,522

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (482,907 ) (427,298 )
Proceeds from asset sales 12,990 20,437
Proceeds from sale and leaseback transaction 1,328,919 -
Sales of investment securities held in trusts 521,535 886,863
Purchases of investment securities held in trusts (521,535 ) (886,863 )
Loan repayments from (loans to) associated companies, net 510,307 (88,292 )
Other 2,209 (28,474 )
Net cash provided from (used for) investing activities 1,371,518 (523,627 )

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

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an
integral part of these statements.

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of FirstEnergy Solutions Corp.:~~

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006 as discussed in Note 3 to those consolidated financial statements) dated April 11, 2007,except as to Note 12, which is as of August 6, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~October 31, 2007~~

~~FIRSTENERGY SOLUTIONS CORP.~~

~~MANAGEMENT’S NARRATIVE~~

~~ANALYSIS OF RESULTS OF OPERATIONS~~

FES’ revenues are primarily from the sale of electricity (provided from FES’ generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and TE to supply each of their PLR obligations through 2008, at prices that take into consideration their respective PUCO authorized billing rates. FES also has a partial requirements wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to supply a portion of each of their respective PLR obligations at fixed prices through 2010. The fixed prices under the partial requirements agreement are expected to remain below wholesale market prices during the term of the agreement. FES also supplies the majority of the PLR requirements of Penn at market-based rates as a result of a competitive solicitation conducted by Penn. FES’ existing contractual obligations to Penn expire on May 31, 2008, but could continue if FES successfully bids in future competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, Maryland and Michigan.

~~Results of Operations~~

In the first nine months of 2007, net income increased to $409 million from $312 million in the first nine months of 2006. The increase in net income was primarily due to higher revenues and lower fuel and other operating expenses, partially offset by higher purchased power costs.

~~Revenues~~

Revenues increased by $198 million in the first nine months of 2007 compared to the same period in 2006 due to increases in revenues from non-affiliated retail generation sales and affiliated wholesale sales, partially offset by lower non-affiliated wholesale sales. Retail generation sales revenues increased as a result of higher unit prices and increased KWH sales. Higher unit prices primarily reflected higher generation rates in the MISO and PJM markets where FES is an alternative supplier. Increased KWH sales to FES’ commercial and industrial customers during the first nine months of 2007 were partially offset by a decrease in sales to residential customers returning to FES’ Ohio utility affiliates for their generation requirements. Affiliated wholesale revenues were higher as a result of increased sales and higher unit prices for sales to the Ohio Companies.

Non-affiliated wholesale revenues decreased as a result of lower generation available for the non-affiliated market due to increased affiliated company power sales requirements under the Ohio Companies’ full-requirements PSA and the partial-requirements power sales agreement with Met-Ed and Penelec.

The increase in sales to the Ohio Companies was due to their higher retail generation sales requirements. Higher unit prices resulted from the provision of the full-requirements PSA under which PSA rates reflect the increase in the Ohio Companies’ retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn as a result of the implementation of its competitive solicitation process in 2007.

~~Transmission revenue decreased $25 million due to reduced retail load in the MISO market, lower transmission rates and reduced financial transmission rights auction revenue.~~

~~Changes in revenues in the first nine months of 2007 from the same period of 2006 are summarized below:~~

Nine Months Ended

Sept 30,

Increase

Revenues by Type of Service

2007

2006

(Decrease)

(In millions)

Non-Affiliated Generation Sales:

Retail

$
547

$
445

$
102

Wholesale

425

509

(84
)
Total Non-Affiliated Generation Sales

972

954

18

Affiliated Generation Sales

2,210

1,997

213

Transmission

71

96

(25
)
Other

5

13

(8
)
Total Revenues

$
3,258

$
3,060

$
198

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated sales in the first nine months of 2007 compared to the same period last year:

Increase

Source of Change in Non-Affiliated Generation Revenues

(Decrease)

(In millions)

Retail:
Effect of 12% increase in sales volumes
$ 52
Change in prices

50

102

Wholesale:
Effect of 26% decrease in sales volumes
(131 )
Change in prices

47

(84
)
Net Increase in Non-Affiliated Generation Revenues
$
18

Source of Change in Affiliated Generation Revenues

Increase

(In millions)

Ohio Companies:
Effect of 4% increase in sales volumes
$ 56
Change in prices

89

145

Pennsylvania Companies:
Effect of 12% increase in sales volumes
54
Change in prices

14

68

Net Increase in Affiliated Generation Revenues
$
213

~~Expenses~~

Total expenses increased by $57 million in the first nine months of 2007 compared with the same period of 2006. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first nine months of 2007 from the same period last year:

Source of Change in Fuel and Purchased Power

Increase
(Decrease)

(In millions)

Nuclear Fuel:
Change due to increased unit costs
$ 3
Change due to volume consumed
5
8
Fossil Fuel:
Change due to decreased unit costs
(4 )
Change due to volume consumed
(45 )
(49 )
Purchased Power:
Change due to increased unit costs
51
Change due to volume purchased
71
122
Net Increase in Fuel and Purchased Power Costs
$
81

Fossil fuel costs decreased $49 million in the first nine months of 2007 primarily as a result of reduced coal and emission allowance costs. Coal costs were lower due to a $14 million inventory adjustment as a result of an interim physical inventory and $23 million from reduced coal consumption reflecting lower generation as a result of planned maintenance outages at Sammis Units 6 and 7 and Eastlake Unit 5 and forced outage at Mansfield Unit 1.

The lower fossil fuel costs were partially offset by higher nuclear fuel costs of $8 million. Higher nuclear fuel costs were due to higher unit costs and increased nuclear generation in the first nine months of 2007 as compared to the same period of 2006.

Purchased power costs increased as a result of increased volumes purchased and higher unit prices. Volumes purchased in the first nine months of 2007 increased by 10.6% due to the outages at the Sammis, Eastlake, Mansfield and Perry plants. Other operating expenses decreased by $43 million in the first nine months of 2007 from the same period of 2006 primarily due to lower nuclear operating costs as a result of fewer outages in 2007 compared to 2006 and reduced employee benefit costs.

~~Depreciation expense increased by $10 million in the first nine months of 2007 primarily due to fossil and nuclear property additions subsequent to the third quarter of 2006.~~

~~General taxes increased by $9 million in the first nine months of 2007 compared to the same period of 2006 as a result of higher property taxes and gross receipts taxes.~~

~~Other Expense~~

Other expense decreased by $15 million in the first nine months of 2007 from the same periods of 2006 primarily as a result of lower interest expense. Lower interest expense reflected the repayment of GAT-related notes to associated companies, partially offset by the issuance of lower-cost pollution control debt subsequent to October 1, 2006.

~~Legal Proceedings~~

New Accounting Standards and Interpretations

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2007

2006

2007

2006

STATEMENTS OF INCOME

(In thousands)

REVENUES:

Electric sales $ 638,336 $ 642,294 $ 1,802,110 $ 1,745,699
Excise tax collections 30,472 31,379 89,077 87,269
Total revenues 668,808 673,673 1,891,187 1,832,968

EXPENSES:

Fuel 2,821 2,954 8,148 8,726
Purchased power 364,709 395,560 1,037,200 971,613
Nuclear operating costs 41,783 44,995 130,951 129,585
Other operating costs 100,265 108,362 285,871 290,776
Provision for depreciation 19,482 18,399 57,440 53,962
Amortization of regulatory assets 53,026 49,717 144,569 147,022
Deferral of new regulatory assets (41,417 ) (44,962 ) (132,410 ) (123,285 )
General taxes 46,158 47,826 141,296 137,652
Total expenses 586,827 622,851 1,673,065 1,616,051

OPERATING INCOME
81,981 50,822 218,122 216,917

OTHER INCOME (EXPENSE):

Investment income 19,827 32,993 67,803 98,853
Miscellaneous income 670 1,639 3,362 835
Interest expense (20,311 ) (24,597 ) (62,749 ) (60,195 )
Capitalized interest 136 698 398 1,832
Subsidiary's preferred stock dividend requirements - (156 ) - (467 )
Total other income 322 10,577 8,814 40,858

INCOME BEFORE INCOME TAXES
82,303 61,399 226,936 257,775

INCOME TAXES
34,089 17,902 79,074 91,239

NET INCOME
48,214 43,497 147,862 166,536

PREFERRED STOCK DIVIDEND REQUIREMENTS AND

REDEMPTION PREMIUM
- 51 - 4,297

EARNINGS ON COMMON STOCK
$ 48,214 $ 43,446 $ 147,862 $ 162,239

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME
$ 48,214 $ 43,497 $ 147,862 $ 166,536

OTHER COMPREHENSIVE INCOME (LOSS):

Pension and other postretirment benefits (3,423 ) - (10,270 ) -
Change in unrealized gain on available for sale securities 2,442 3,795 7,415 5,467
Other comprehensive income (loss) (981 ) 3,795 (2,855 ) 5,467
Income tax expense (benefit) related to other
comprehensive income (573 ) 1,369 (1,688 ) 1,972
Other comprehensive income (loss), net of tax (408 ) 2,426 (1,167 ) 3,495

TOTAL COMPREHENSIVE INCOME
$ 47,806 $ 45,923 $ 146,695 $ 170,031

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
statements.

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

September 30,

December 31,

2007

2006

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 727 $ 712
Receivables-
Customers (less accumulated provisions of $8,518,000 and $15,033,000,
respectively, for uncollectible accounts) 271,680 234,781
Associated companies 167,686 141,084
Other (less accumulated provisions of $5,548,000 and $1,985,000,
respectively, for uncollectible accounts) 20,093 13,496
Notes receivable from associated companies 626,841 458,647
Prepayments and other 17,148 13,606
1,104,175 862,326
UTILITY PLANT:

In service 2,722,468 2,632,207
Less - Accumulated provision for depreciation 1,053,942 1,021,918
1,668,526 1,610,289
Construction work in progress 42,494 42,016
1,711,020 1,652,305
OTHER PROPERTY AND INVESTMENTS:

Long-term notes receivable from associated companies 365,767 1,219,325
Investment in lease obligation bonds 274,077 291,393
Nuclear plant decommissioning trusts 128,168 118,209
Other 36,756 38,160
804,768 1,667,087
DEFERRED CHARGES AND OTHER ASSETS:

Regulatory assets 717,311 741,564
Pension assets 106,682 68,420
Property taxes 60,080 60,080
Unamortized sale and leaseback costs 46,384 50,136
Other 44,457 18,696
974,914 938,896
$ 4,594,877 $ 5,120,614
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ 442,264 $ 159,852
Short-term borrowings-
Associated companies - 113,987
Other 52,609 3,097
Accounts payable-
Associated companies 200,104 115,252
Other 17,766 13,068
Accrued taxes 141,516 187,306
Accrued interest 17,435 24,712
Other 101,543 64,519
973,237 681,793
CAPITALIZATION:

Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 and 80 shares outstanding, respectively 1,220,173 1,708,441
Accumulated other comprehensive income 2,041 3,208
Retained earnings 257,870 260,736
Total common stockholder's equity 1,480,084 1,972,385
Long-term debt and other long-term obligations 836,430 1,118,576
2,316,514 3,090,961
NONCURRENT LIABILITIES:

Accumulated deferred income taxes 676,784 674,288
Accumulated deferred investment tax credits 17,856 20,532
Asset retirement obligations 92,157 88,223
Retirement benefits 159,096 167,379
Deferred revenues - electric service programs 59,255 86,710
Other 299,978 310,728
1,305,126 1,347,860
COMMITMENTS AND CONTINGENCIES (Note 10)

$ 4,594,877 $ 5,120,614

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of
these balance sheets.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended

September 30,

2007

2006

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 147,862 $ 166,536
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 57,440 53,962
Amortization of regulatory assets 144,569 147,022
Deferral of new regulatory assets (132,410 ) (123,285 )
Amortization of lease costs 28,567 28,600
Deferred income taxes and investment tax credits, net (29,155 ) (27,850 )
Accrued compensation and retirement benefits (34,572 ) 2,985
Pension trust contribution (20,261 ) -
Decrease (increase) in operating assets-
Receivables (70,098 ) 26,198
Prepayments and other current assets (3,542 ) (4,172 )
Increase (decrease) in operating liabilities-
Accounts payable 89,550 (24,937 )
Accrued taxes (37,355 ) (27,826 )
Accrued interest (7,277 ) 12,839
Electric service prepayment programs (27,455 ) (24,975 )
Other 7,260 2,570
Net cash provided from operating activities 113,123 207,667

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt - 592,763
Equity contributions from parent 11,621 -
Redemptions and Repayments-
Common stock (500,000 ) (500,000 )
Preferred stock - (63,893 )
Long-term debt (1,190 ) (138,085 )
Short-term borrowings, net (64,475 ) (177,595 )
Dividend Payments-
Common stock (150,000 ) (73,000 )
Preferred stock - (1,369 )
Net cash used for financing activities (704,044 ) (361,179 )

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (109,461 ) (94,278 )
Sales of investment securities held in trusts 31,624 32,826
Purchases of investment securities held in trusts (33,586 ) (34,209 )
Loan repayments from associated companies, net 685,364 148,199
Cash investments 17,316 93,900
Other (321 ) 6,848
Net cash provided from investing activities 590,936 153,286

Net increase (decrease) in cash and cash equivalents 15 (226 )
Cash and cash equivalents at beginning of period 712 929
Cash and cash equivalents at end of period $ 727 $ 703

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral
part of these statements.

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of Ohio Edison Company:~~

We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 3, Note 2(G) and Note 11 to the consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~October 31, 2007~~

~~OHIO EDISON COMPANY~~

~~MANAGEMENT’S NARRATIVE~~

~~ANALYSIS OF RESULTS OF OPERATIONS~~

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. OE also provides generation services to those customers electing to retain OE as their power supplier. OE’s power supply requirements are provided by FES – an affiliated company.

~~Results of Operations~~

In the first nine months of 2007, earnings on common stock decreased to $148 million from $162 million in the same period of 2006. The decrease in earnings primarily resulted from higher purchased power costs and lower other income, partially offset by higher electric sales revenues.

~~Revenues~~

Revenues increased by $58 million or 3.2% in the first nine months of 2007 compared with the same period in 2006, primarily due to a $65 million increase in retail generation revenues, partially offset by decreases in revenues from distribution throughput of $16 million.

Higher retail generation revenues from residential customers reflected increased sales volume and the impact of higher average unit prices. Weather conditions in the first nine months of 2007 compared to the same period in 2006 contributed to the higher KWH sales to residential customers (heating degree days increased 11.5% and 8.4% and cooling degree days increased by 26.9% and 25.2% in OE’s and Penn’s service territories, respectively). Commercial retail generation revenues increased primarily due to higher average unit prices, partially offset by reduced KWH sales. Average prices increased due to the higher generation prices that were effective in January 2007 under Penn’s competitive RFP process. Retail generation revenues from the industrial sector decreased primarily due to an increase in customer shopping in Penn’s service territory in the first nine months of 2007 as compared to the same period in 2006. The percentage of shopping customers increased to 27.7 percent in the first nine months of 2007 from 15.8 percent in the first nine months of 2006.

~~Changes in retail generation sales and revenues in the first nine months of 2007 from the corresponding period of 2006 are summarized in the following tables:~~

~~Retail Generation KWH Sales~~	~~Increase (Decrease)~~

~~Residential~~		~~7.4~~	%
~~Commercial~~		~~(1.4~~	)%
~~Industrial~~		~~(16.0~~	)%
~~Net Decrease in Generation Sales~~		~~(3.7~~	)%

Retail Generation Revenues

Increase (Decrease)

(In millions)

Residential $ 80
Commercial 23
Industrial (38 )
Net Increase in Generation Revenues

$
65

A small increase in distribution revenues from residential customers was more than offset by decreases in distribution revenues from commercial and industrial customers. The increase from residential customers reflected higher deliveries due to the favorable weather conditions described above in the first nine months of 2007 as compared to the same period in 2006, partially offset by lower composite unit prices. Reduced distribution revenues from commercial customers in the first nine months of 2007 resulted from lower unit prices, partially offset by increased KWH deliveries. Distribution revenues from industrial customers decreased in the first nine months of 2007 as a result of lower unit prices and reduced KWH deliveries.

~~Changes in distribution KWH deliveries and revenues in the first nine months of 2007 from the corresponding period of 2006 are summarized in the following tables.~~

~~Distribution KWH Deliveries~~	~~Increase (Decrease)~~

~~Residential~~		~~5.8~~	%
~~Commercial~~		~~3.3~~	%
~~Industrial~~		~~(2.2~~	)%
~~Net Increase in Distribution Deliveries~~		~~2.2~~	%

Distribution Revenues

Increase (Decrease)

(In millions)

Residential $ 2
Commercial (5 )
Industrial (13 )
Net Decrease in Distribution Revenues

$
(16
)

~~Expenses~~

~~Total expenses increased by $57 million in the first nine months of 2007 from the same period of 2006. The following table presents changes from the prior year by expense category.~~

Expenses – Changes

Increase (Decrease)

(In millions)

Purchased power costs $ 65
Nuclear operating costs 1
Other operating costs (5 )
Provision for depreciation 3
Amortization of regulatory assets (2 )
Deferral of new regulatory assets (9 )
General taxes 4
Net Increase in Expenses

$
57

Higher purchased power costs in the first nine months of 2007 primarily reflected higher unit prices under Penn’s competitive RFP process and OE’s PSA with FES. The decrease in other operating costs for the first nine months of 2007 was primarily due to lower employee benefit expenses, partially offset by higher transmission expenses related to MISO operations. Higher depreciation expense in the first nine months of 2007 reflected capital additions subsequent to the third quarter of 2006. The increase in the deferral of new regulatory assets for the first nine months of 2007��was primarily due to increases in MISO cost deferrals and RCP distribution cost deferrals, partially offset by lower RCP fuel cost deferrals. General taxes were higher in the first nine months of 2007 as compared to the same period last year as a result of higher real and personal property taxes and KWH excise taxes.

~~Other Income~~

Other income decreased $32 million in the first nine months of 2007 as compared with the same period of 2006 primarily due to reductions in interest income on notes receivable resulting from principal payments from associated companies since the third quarter of 2006. Higher interest expense also contributed to the decrease in other income in the first nine months of 2007, with interest expense associated with OE’s issuance of $600 million of long-term debt in June 2006 being partially offset by debt redemptions since the third quarter of 2006.

~~Legal Proceedings~~

~~New Accounting Standards and Interpretations~~

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2007

2006

2007

2006

(In thousands)

REVENUES:

Electric sales $ 510,577 $ 497,336 $ 1,366,396 $ 1,304,525
Excise tax collections 18,514 18,587 53,009 51,579
Total revenues 529,091 515,923 1,419,405 1,356,104

EXPENSES:

Fuel 12,160 12,748 39,683 39,724
Purchased power 216,194 229,779 575,520 531,490
Other operating costs 85,114 81,510 243,140 222,841
Provision for depreciation 18,913 17,524 56,094 45,775
Amortization of regulatory assets 42,077 38,826 110,253 99,832
Deferral of new regulatory assets (37,692 ) (39,060 ) (114,708 ) (101,283 )
General taxes 37,930 34,228 110,922 100,808
Total expenses 374,696 375,555 1,020,904 939,187

OPERATING INCOME
154,395 140,368 398,501 416,917

OTHER INCOME (EXPENSE):

Investment income 13,805 24,715 47,816 76,325
Miscellaneous income (expense) (760 ) 813 3,197 6,209
Interest expense (34,423 ) (34,774 ) (107,430 ) (104,140 )
Capitalized interest 309 836 655 2,346
Total other expense (21,069 ) (8,410 ) (55,762 ) (19,260 )

INCOME BEFORE INCOME TAXES
133,326 131,958 342,739 397,657

INCOME TAXES
54,610 48,496 131,525 150,730

NET INCOME
78,716 83,462 211,214 246,927

OTHER COMPREHENSIVE INCOME:

Pension and other postretirement benefits 1,202 - 3,607 -
Income tax expense related to other comprehensive income 356 - 1,068 -
Other comprehensive income, net of tax 846 - 2,539 -

TOTAL COMPREHENSIVE INCOME
$ 79,562 $ 83,462 $ 213,753 $ 246,927

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral
part of these statements.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

September 30,

December 31,

2007

2006

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 234 $ 221
Receivables-
Customers (less accumulated provisions of $8,057,000 and $6,783,000
respectively, for uncollectible accounts) 304,608 245,193
Associated companies 53,564 249,735
Other 21,331 14,240
Notes receivable from associated companies 41,054 27,191
Prepayments and other 1,510 2,314
422,301 538,894
UTILITY PLANT:

In service 2,199,913 2,136,766
Less - Accumulated provision for depreciation 844,600 819,633
1,355,313 1,317,133
Construction work in progress 55,382 46,385
1,410,695 1,363,518
OTHER PROPERTY AND INVESTMENTS:

Long-term notes receivable from associated companies 265,660 486,634
Investment in lessor notes 463,433 519,611
Other 10,302 13,426
739,395 1,019,671
DEFERRED CHARGES AND OTHER ASSETS:

Goodwill 1,688,521 1,688,521
Regulatory assets 855,618 854,588
Pension assets 16,791 -
Property taxes 65,000 65,000
Other 42,993 33,306
2,668,923 2,641,415
$ 5,241,314 $ 5,563,498
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ 266,271 $ 120,569
Short-term borrowings-
Associated companies 73,459 218,134
Other 100,000 -
Accounts payable-
Associated companies 237,072 365,678
Other 6,194 7,194
Accrued taxes 132,941 128,829
Accrued interest 41,393 19,033
Lease market valuation liability 58,750 60,200
Other 44,931 52,101
961,011 971,738

CAPITALIZATION:

Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding 873,037 860,133
Accumulated other comprehensive loss (101,892 ) (104,431 )
Retained earnings 620,155 713,201
Total common stockholder's equity 1,391,300 1,468,903
Long-term debt and other long-term obligations 1,670,898 1,805,871
3,062,198 3,274,774
NONCURRENT LIABILITIES:

Accumulated deferred income taxes 461,410 470,707
Accumulated deferred investment tax credits 18,994 20,277
Lease market valuation liability 491,085 547,800
Retirement benefits 110,620 122,862
Deferred revenues - electric service programs 34,768 51,588
Other 101,228 103,752
1,218,105 1,316,986
COMMITMENTS AND CONTINGENCIES (Note 10)

$ 5,241,314 $ 5,563,498

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these balance sheets.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended

September 30,

2007

2006

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 211,214 $ 246,927
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 56,094 45,775
Amortization of regulatory assets 110,253 99,832
Deferral of new regulatory assets (114,708 ) (101,283 )
Deferred rents and lease market valuation liability (46,327 ) (55,166 )
Deferred income taxes and investment tax credits, net (40,964 ) (9,513 )
Accrued compensation and retirement benefits 2,575 2,681
Pension trust contribution (24,800 ) -
Decrease (increase) in operating assets-
Receivables 140,359 189
Prepayments and other current assets 661 (387 )
Increase (decrease) in operating liabilities-
Accounts payable (143,210 ) 29,681
Accrued taxes 4,545 (14,588 )
Accrued interest 22,360 12,427
Electric service prepayment programs (16,819 ) (13,623 )
Other 2,996 (5,270 )
Net cash provided from operating activities 164,229 237,682

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt 247,424 -
Equity contributions from parent 12,756 -
Redemptions and Repayments-
Long-term debt (223,555 ) (118,295 )
Short-term borrowings, net (59,328 ) (58,819 )
Dividend Payments-
Common stock (304,000 ) (118,000 )
Net cash used for financing activities (326,703 ) (295,114 )

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (100,583 ) (89,771 )
Loan repayments from (loans to) associated companies, net (13,863 ) 108,034
Collection of principal on long-term notes receivable 220,974 -
Redemption of lessor notes 56,177 44,553
Other (218 ) (5,368 )
Net cash provided from investing activities 162,487 57,448

Net increase in cash and cash equivalents 13 16
Cash and cash equivalents at beginning of period 221 207
Cash and cash equivalents at end of period $ 234 $ 223

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of The Cleveland Electric Illuminating Company:~~

We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 11 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~October 31, 2007~~

~~THE CLEVELAND ELECTRIC ILLUMINATING COMPANY~~

~~MANAGEMENT’S NARRATIVE~~

~~ANALYSIS OF RESULTS OF OPERATIONS~~

~~Results of Operations~~

Net income in the first nine months of 2007 decreased to $211 million from $247 million in the same period of 2006. The decrease resulted primarily from higher purchased power costs and other operating costs, partially offset by higher revenues.

~~Revenues~~

Revenues increased by $63 million or 5% in the first nine months of 2007 compared to the same period of 2006 primarily due to higher retail generation and wholesale revenues. Retail generation revenues increased by $38 million due to increased KWH sales and higher composite unit prices for all customer classes. More weather-related usage in the first nine months of 2007 compared to the same period of 2006 primarily contributed to the increased KWH sales in the residential and commercial sectors (cooling degree days increased 19% and heating degree days increased 15% from the same period in 2006). Increased KWH sales in the industrial sector reflected a slight decrease in customer shopping.

Wholesale generation revenues increased by $17 million in the first nine months of 2007 compared to the corresponding period of 2006. The increase was primarily due to higher unit prices for PSA sales. CEI sells power from its leasehold interests in the Bruce Mansfield plant to FGCO.

~~Increases in retail generation sales and revenues in the first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables:~~

~~Retail Generation KWH Sales~~	~~Increase~~

~~Residential~~		~~4.3~~	%
~~Commercial~~		~~6.0~~	%
~~Industrial~~		~~1.2~~	%
~~Increase in Retail Generation Sales~~		~~3.2~~	%

Retail Generation Revenues

Increase

(In millions)

Residential $ 9
Commercial 15
Industrial 14
Increase in Generation Revenues

$
38

Revenues from distribution throughput increased by $5 million in the first nine months of 2007 compared to the same period of 2006 primarily due to increased KWH deliveries to all customer classes, partially offset by lower composite unit prices for the industrial sector. Increased KWH deliveries were primarily a result of the weather in 2007 as described above.

~~Changes in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables.~~

~~Distribution KWH Deliveries~~	~~Increase~~

~~Residential~~		~~4.5~~	%
~~Commercial~~		~~3.7~~	%
~~Industrial~~		~~0.7~~	%
~~Increase in Distribution Deliveries~~		~~2.5~~	%

Distribution Revenues

Increase
(Decrease)

(In millions)

Residential $ 6
Commercial 6
Industrial (7 )
Net Increase in Distribution Revenues

$
5

~~Expenses~~

~~Total expenses increased by $82 million in the first nine months of 2007 compared to the same period of 2006. The following table presents the change from the prior year by expense category:~~

Expenses - Changes

Increase
(Decrease)

(in millions)

Purchased power costs $ 44
Other operating costs 20
Provision for depreciation 10
Amortization of regulatory assets 11
Deferral of new regulatory assets (13 )
General taxes 10
Net Increase in Expenses
$ 82

Higher purchased power costs in the first nine months of 2007 compared to the corresponding period of 2006 primarily reflect higher unit prices associated with the PSA with FES and an increase in purchased power to meet CEI’s higher retail generation sales requirements. Higher other operating costs in the first nine months of 2007 compared to the same period of 2006 reflect increases in MISO transmission related expenses due to increased transmission volumes. The increased depreciation in the first nine months of 2007 is primarily due to property additions since the third quarter of 2006 and the absence of a credit adjustment in the second quarter of 2006 that related to prior periods ($6.5 million pre-tax, $4 million net of tax).

The increased amortization of regulatory assets in the first nine months of 2007 compared to the corresponding period of 2006 was due to increased transition cost amortization reflecting the higher KWH sales discussed above. The increase in the deferral of new regulatory assets in the first nine months of 2007 reflect a higher level of MISO costs that were deferred in excess of transmission revenues recognized and increased distribution cost deferrals under CEI’s RCP. General taxes were higher in the first nine months of 2007 compared to the same period of 2006 primarily as a result of higher real and personal property taxes.

~~Other Expense~~

Other expense increased by $37 million in the first nine months of 2007 compared to the corresponding period of 2006 primarily due to lower investment income on associated company notes receivable in 2007. CEI received principal repayments from FGCO and NGC subsequent to the third quarter of 2006 on notes receivable related to the generation asset transfers.

~~Legal Proceedings~~

~~New Accounting Standards and Interpretations~~

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2007

2006

2007

2006

STATEMENTS OF INCOME

(In thousands)

REVENUES:

Electric sales $ 261,736 $ 254,979 $ 728,429 $ 684,992
Excise tax collections 7,926 7,858 22,026 21,420
Total revenues 269,662 262,837 750,455 706,412

EXPENSES:

Fuel 8,784 9,399 29,392 28,799
Purchased power 112,502 112,389 304,947 268,468
Nuclear operating costs 17,705 19,252 53,272 54,450
Other operating costs 47,212 44,253 136,297 124,396
Provision for depreciation 9,231 8,386 27,475 24,723
Amortization of regulatory assets 30,460 27,336 79,284 73,909
Deferral of new regulatory assets (15,645 ) (15,340 ) (47,373 ) (43,186 )
General taxes 11,912 13,406 38,646 38,590
Total expenses 222,161 219,081 621,940 570,149

OPERATING INCOME
47,501 43,756 128,515 136,263

OTHER INCOME (EXPENSE):

Investment income 6,721 9,724 21,255 28,449
Miscellaneous expense (2,153 ) (1,933 ) (7,309 ) (6,543 )
Interest expense (8,786 ) (4,940 ) (25,205 ) (13,614 )
Capitalized interest 220 277 467 835
Total other income (expense) (3,998 ) 3,128 (10,792 ) 9,127

INCOME BEFORE INCOME TAXES
43,503 46,884 117,723 145,390

INCOME TAXES
18,435 17,706 44,924 54,834

NET INCOME
25,068 29,178 72,799 90,556

PREFERRED STOCK DIVIDEND REQUIREMENTS
- 1,161 - 3,597

EARNINGS ON COMMON STOCK
$ 25,068 $ 28,017 $ 72,799 $ 86,959

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME
$ 25,068 $ 29,178 $ 72,799 $ 90,556

OTHER COMPREHENSIVE INCOME:

Pension and other postretirement benefits 574 - 1,720 -
Change in unrealized gain on available for sale securities 1,946 1,379 1,656 432
Other comprehensive income 2,520 1,379 3,376 432
Income tax expense related to other
comprehensive income 902 498 1,193 156
Other comprehensive income, net of tax 1,618 881 2,183 276

TOTAL COMPREHENSIVE INCOME
$ 26,686 $ 30,059 $ 74,982 $ 90,832

The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of
these statements.

~~100~~

THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

September 30,

December 31,

2007

2006

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 20 $ 22
Receivables-
Customers 335 772
Associated companies 31,180 13,940
Other (less accumulated provisions of $518,000 and $430,000,
respectively, for uncollectible accounts) 3,600 3,831
Notes receivable from associated companies 79,188 100,545
Prepayments and other 627 851
114,950 119,961
UTILITY PLANT:

In service 913,191 894,888
Less - Accumulated provision for depreciation 406,949 394,225
506,242 500,663
Construction work in progress 26,665 16,479
532,907 517,142
OTHER PROPERTY AND INVESTMENTS:

Investment in lessor notes 154,674 169,493
Long-term notes receivable from associated companies 92,700 128,858
Nuclear plant decommissioning trusts 64,598 61,094
Other 1,778 1,871
313,750 361,316
DEFERRED CHARGES AND OTHER ASSETS:

Goodwill 500,576 500,576
Regulatory assets 214,896 247,595
Pension assets 5,962 -
Property taxes 22,010 22,010
Other 29,427 30,042
772,871 800,223
$ 1,734,478 $ 1,798,642
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ 55,134 $ 30,000
Accounts payable-
Associated companies 103,250 84,884
Other 4,043 4,021
Notes payable to associated companies 190,758 153,567
Accrued taxes 52,865 47,318
Lease market valuation liability 23,655 24,600
Other 32,906 37,551
462,611 381,941
CAPITALIZATION:

Common stockholder's equity-
Common stock, $5 par value, authorized 60,000,000 shares -
29,402,054 shares outstanding 147,010 147,010
Other paid-in capital 172,949 166,786
Accumulated other comprehensive loss (34,621 ) (36,804 )
Retained earnings 157,139 204,423
Total common stockholder's equity 442,477 481,415
Long-term debt 303,220 358,281
745,697 839,696
NONCURRENT LIABILITIES:

Accumulated deferred income taxes 141,813 161,024
Accumulated deferred investment tax credits 10,389 11,014
Lease market valuation liability 192,774 218,800
Retirement benefits 77,275 77,843
Asset retirement obligations 27,899 26,543
Deferred revenues - electric service programs 15,896 23,546
Other 60,124 58,235
526,170 577,005
COMMITMENTS AND CONTINGENCIES (Note 10)

$ 1,734,478 $ 1,798,642

The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are
an integral part of these balance sheets.

~~101~~

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended

September 30,

2007

2006

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 72,799 $ 90,556
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 27,475 24,723
Amortization of regulatory assets 79,284 73,909
Deferral of new regulatory assets (47,373 ) (43,186 )
Deferred rents and lease market valuation liability (23,551 ) (27,114 )
Deferred income taxes and investment tax credits, net (32,530 ) (28,603 )
Accrued compensation and retirement benefits 3,493 2,766
Pension trust contribution (7,659 ) -
Decrease (increase) in operating assets-
Receivables (13,368 ) (25,069 )
Prepayments and other current assets 224 (75 )
Increase (decrease) in operating liabilities-
Accounts payable 9,515 1,102
Accrued taxes 7,463 3,458
Accrued interest 3,444 (709 )
Electric service prepayment programs (7,650 ) (6,744 )
Other 1,953 1,716
Net cash provided from operating activities 73,519 66,730

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Short-term borrowings, net 37,191 113,886
Equity contribution from parent 6,125 -
Redemptions and Repayments-
Preferred stock - (30,000 )
Long-term debt (30,014 ) (53,650 )
Dividend Payments-
Common stock (120,000 ) (50,000 )
Preferred stock - (3,597 )
Net cash used for financing activities (106,698 ) (23,361 )

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (41,573 ) (45,661 )
Loan repayments from (loans to) associated companies, net 21,438 (61,549 )
Collection of principal on long-term notes receivable 36,077 53,766
Redemption of lessor notes 14,819 9,275
Sales of investment securities held in trusts 39,260 50,255
Purchases of investment securities held in trusts (39,557 ) (50,433 )
Other 2,713 983
Net cash provided from (used for) investing activities 33,177 (43,364 )

Net increase (decrease) in cash and cash equivalents (2 ) 5
Cash and cash equivalents at beginning of period 22 15
Cash and cash equivalents at end of period $ 20 $ 20

The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an
integral part of these statements.

~~102~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of The Toledo Edison Company:~~

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006 as discussed in Note 3 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~October 31, 2007~~

~~103~~

~~THE TOLEDO EDISON COMPANY~~

~~MANAGEMENT’S NARRATIVE~~

~~ANALYSIS OF RESULTS OF OPERATIONS~~

~~Results of Operations~~

Earnings on common stock in the first nine months of 2007 decreased to $73 million from $87 million in the same period of 2006. The decrease resulted primarily from higher purchased power and other operating costs and increased interest expense, partially offset by higher electric sales revenues.

~~Revenues~~

Revenues increased $44 million or 6.2% in the first nine months of 2007 compared to the same period of 2006 primarily due to increases in retail generation revenues ($24 million), wholesale generation revenues ($11 million) and distribution revenues ($6 million). Retail generation revenues increased in the first nine months of 2007 due to higher average prices and increased sales volume across all customer classes compared to the same period of 2006. Average prices increased primarily due to higher composite unit prices for retail generation shopping customers returning to TE. The increase in sales volume also reflects increased weather-related usage in the first nine months of 2007 (heating and cooling degree days increased 15.2% and 7.2%, respectively, from the same period of 2006).

The increase in wholesale revenues resulted primarily from increased KWH sales to associated companies and higher unit prices. TE sells KWH from its leasehold interests in Beaver Valley Unit 2 and the Bruce Mansfield Plant to CEI and FGCO, respectively.

~~Increases in retail electric generation KWH sales and revenues in the first nine months of 2007 from the same period of 2006 are summarized in the following tables.~~

~~Retail Generation KWH Sales~~	~~Increase~~

~~Residential~~		~~8.0~~	%
~~Commercial~~		~~3.1~~	%
~~Industrial~~		~~1.0~~	%
~~Increase in Retail Generation Sales~~		~~3.1~~	%

Retail Generation Revenues

Increase

(In millions)

Residential $ 8
Commercial 4
Industrial 12
Increase in Retail Generation Revenues

$
24

Revenues from distribution throughput increased by $6 million in the first nine months of 2007 compared to the same period in 2006 due to higher KWH deliveries to all customer sectors, partially offset by lower average unit prices for industrial customers. The higher KWH deliveries to residential and commercial customers in the first nine months of 2007 reflected the weather impacts described above.

~~Changes in distribution KWH deliveries and revenues in the first nine months of 2007 from the same period of 2006 are summarized in the following tables.~~

~~Distribution KWH Deliveries~~	~~Increase~~

~~Residential~~		~~5.5~~	%
~~Commercial~~		~~2.6~~	%
~~Industrial~~		~~1.1~~	%
~~Increase in Distribution Deliveries~~		~~2.5~~	%

~~104~~

Distribution Revenues

Increase (Decrease)

(In millions)

   Residential $ 7
   Commercial 3
   Industrial (4 )
   Net Increase in Distribution Revenues

$
6

~~Expenses~~

~~Total expenses increased $52 million in the first nine months of 2007 from the same period of 2006. The following table presents changes from the prior year by expense category:~~

Expenses – Changes

Increase (Decrease)

(In millions)

Purchased power costs
$
37

Nuclear operating costs

(1
)
Other operating costs

12

Provision for depreciation

3

Amortization of regulatory assets

5

Deferral of new regulatory assets

(4
)
Net increase in expenses

$
52

Higher purchased power costs in the first nine months of 2007 compared to the same period of 2006 reflected higher unit prices associated with the PSA with FES and an increase in KWH purchases to meet the higher retail generation sales requirements. Other operating costs were higher due to an $11 million increase in MISO network transmission expenses in the first nine months of 2007. Depreciation expense was higher due to an increase in depreciable property, reflecting plant additions since the third quarter of 2006. Higher amortization of regulatory assets was due to increased amortization of transition cost deferrals ($3 million) and MISO transmission deferrals ($2 million). The change in the deferral of new regulatory assets was primarily due to increased deferrals for MISO transmission expenses ($7 million) and RCP distribution costs ($4 million), partially offset by lower RCP fuel cost deferrals ($5 million).

~~Other Expense~~

Other expense increased $20 million in the first nine months of 2007 compared to the same period of 2006 primarily due to lower investment income and higher interest expense. The decrease in investment income resulted primarily from the principal repayments since the third quarter of 2006 on notes receivable from associated companies. The higher interest expense is principally associated with new long-term debt issued in November 2006.

~~Legal Proceedings~~

~~New Accounting Standards and Interpretations~~

~~105~~

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2007

2006

2007

2006

STATEMENTS OF INCOME

(In thousands)

REVENUES:

Electric sales $ 1,018,049 $ 895,389 $ 2,457,146 $ 2,059,499
Excise tax collections 15,168 15,679 39,849 38,845
Total revenues 1,033,217 911,068 2,496,995 2,098,344

EXPENSES:

Purchased power 654,418 546,125 1,505,420 1,204,880
Other operating costs 87,010 90,578 236,225 245,711
Provision for depreciation 22,032 21,099 63,867 62,553
Amortization of regulatory assets 107,837 78,052 296,955 210,323
General taxes 18,631 19,187 51,183 49,691
Total expenses 889,928 755,041 2,153,650 1,773,158

OPERATING INCOME
143,289 156,027 343,345 325,186

OTHER INCOME (EXPENSE):

Miscellaneous income 2,967 2,091 9,266 8,162
Interest expense (24,666 ) (21,437 ) (71,576 ) (62,420 )
Capitalized interest 483 1,004 1,559 2,933
Total other expense (21,216 ) (18,342 ) (60,751 ) (51,325 )

INCOME BEFORE INCOME TAXES
122,073 137,685 282,594 273,861

INCOME TAXES
46,275 58,316 118,637 120,506

NET INCOME
75,798 79,369 163,957 153,355

PREFERRED STOCK DIVIDEND REQUIREMENTS
- 917 - 1,167

EARNINGS ON COMMON STOCK
$ 75,798 $ 78,452 $ 163,957 $ 152,188

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME
$ 75,798 $ 79,369 $ 163,957 $ 153,355

OTHER COMPREHENSIVE INCOME (LOSS):

Pension and other postretirement benefits (2,114 ) - (6,344 ) -
Unrealized gain on derivative hedges 69 100 235 207
Other comprehensive income (loss) (2,045 ) 100 (6,109 ) 207
Income tax expense (benefit) related to other
comprehensive income (994 ) 41 (2,973 ) 84
Other comprehensive income (loss), net of tax (1,051 ) 59 (3,136 ) 123

TOTAL COMPREHENSIVE INCOME
$ 74,747 $ 79,428 $ 160,821 $ 153,478

The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral
part of these statements.

~~106~~

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

September 30,

December 31,

2007

2006

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 77 $ 41
Receivables-
Customers (less accumulated provisions of $4,821,000 and $3,524,000,
respectively, for uncollectible accounts) 396,700 254,046
Associated companies 369 11,574
Other (less accumulated provisions of $718,000 and $204,000,
respectively, for uncollectible accounts) 62,235 40,023
Notes receivable - associated companies 22,734 24,456
Materials and supplies, at average cost 1,915 2,043
Prepaid taxes 41,670 13,333
Other 14,080 18,076
539,780 363,592
UTILITY PLANT:

In service 4,122,325 4,029,070
Less - Accumulated provision for depreciation 1,490,846 1,473,159
2,631,479 2,555,911
Construction work in progress 84,199 78,728
2,715,678 2,634,639
OTHER PROPERTY AND INVESTMENTS:

Nuclear fuel disposal trust 172,278 171,045
Nuclear plant decommissioning trusts 177,217 164,108
Other 2,075 2,047
351,570 337,200
DEFERRED CHARGES AND OTHER ASSETS:

Regulatory assets 1,757,516 2,152,332
Goodwill 1,826,190 1,962,361
Pension assets 43,183 14,660
Other 15,124 17,781
3,642,013 4,147,134
$ 7,249,041 $ 7,482,565
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ 26,680 $ 32,683
Short-term borrowings-
Associated companies 155,395 186,540
Accounts payable-
Associated companies 22,399 80,426
Other 211,788 160,359
Accrued taxes 25,793 1,451
Accrued interest 27,520 14,458
Cash collateral from suppliers 68 32,311
Other 85,746 96,139
555,389 604,367
CAPITALIZATION:

Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares-
14,421,637 and 15,009,335 shares outstanding, respectively 144,216 150,093
Other paid-in capital 2,657,775 2,908,279
Accumulated other comprehensive loss (47,390 ) (44,254 )
Retained earnings 266,342 145,480
Total common stockholder's equity 3,020,943 3,159,598
Long-term debt and other long-term obligations 1,568,296 1,320,341
4,589,239 4,479,939
NONCURRENT LIABILITIES:

Power purchase contract loss liability 872,305 1,182,108
Accumulated deferred income taxes 762,782 803,944
Nuclear fuel disposal costs 190,524 183,533
Asset retirement obligations 88,334 84,446
Other 190,468 144,228
2,104,413 2,398,259
COMMITMENTS AND CONTINGENCIES (Note 10)

$ 7,249,041 $ 7,482,565

The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an
integral part of these balance sheets.

~~107~~

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended

September 30,

2007

2006

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 163,957 $ 153,355
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 63,867 62,553
Amortization of regulatory assets 296,955 210,323
Deferred purchased power and other costs (157,201 ) (213,621 )
Deferred income taxes and investment tax credits, net (23,786 ) 25,217
Accrued compensation and retirement benefits (17,543 ) (4,196 )
Cash collateral returned to suppliers (32,243 ) (108,926 )
Pension trust contribution (17,800 ) -
Decrease (increase) in operating assets-
Receivables (153,660 ) (50,337 )
Materials and supplies 127 86
Prepaid taxes (28,337 ) (29,923 )
Other current assets 2,079 (2,118 )
Increase (decrease) in operating liabilities-
Accounts payable (6,598 ) (8,131 )
Accrued taxes 29,318 (16,992 )
Accrued interest 13,062 16,296
Tax collections payable (12,478 ) (10,316 )
Other (7,440 ) (4,814 )
Net cash provided from operating activities 112,279 18,456

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt 549,999 382,400
Equity contribution from parent 4,636 -
Redemptions and Repayments-
Long-term debt (324,256 ) (162,157 )
Short-term borrowings, net (31,145 ) (44,162 )
Common stock (125,000 ) -
Preferred stock - (13,461 )
Dividend Payments-
Common stock (43,000 ) (45,000 )
Preferred stock - (354 )
Net cash provided from financing activities 31,234 117,266

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (144,668 ) (123,540 )
Loan repayments from (loans to) associated companies, net 1,722 (8,638 )
Sales of investment securities held in trusts 169,649 169,676
Purchases of investment securities held in trusts (171,820 ) (171,847 )
Other 1,640 (1,417 )
Net cash used for investing activities (143,477 ) (135,766 )

Net increase (decrease) in cash and cash equivalents 36 (44 )
Cash and cash equivalents at beginning of period 41 102
Cash and cash equivalents at end of period $ 77 $ 58

The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.

~~108~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of Jersey Central Power & Light Company:~~

We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, as discussed in Note 3 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~October 31, 2007~~

~~109~~

~~JERSEY CENTRAL POWER & LIGHT COMPANY~~

~~MANAGEMENT’S NARRATIVE~~

~~ANALYSIS OF RESULTS OF OPERATIONS~~

JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also provides generation services to those customers electing to retain JCP&L as their power supplier.

~~Results of Operations~~

Earnings on common stock increased to $164 million in the first nine months of 2007 compared to $152 million for the same period in 2006. The increase was primarily due to higher revenues and lower other operating costs, partially offset by higher purchased power costs and increased amortization of regulatory assets.

~~Revenues~~

Revenues increased $399 million or 19% in the first nine months of 2007 compared with the same period of 2006. Retail and wholesale generation revenues increased by $250 million and $49 million, respectively, in the first nine months of 2007.

Retail generation revenues from all customer classes increased in the first nine months of 2007 compared to 2006 due to higher unit prices resulting from the BGS auctions effective June 1, 2006 and June 1, 2007 and higher retail generation KWH sales. Sales volume increased as a result of weather conditions in the first nine months of 2007 (heating degree days were 15.8% higher than the first nine months of 2006 and cooling degree days decreased slightly). Industrial generation KWH sales declined in the first nine months of 2007 from the same period in 2006 due to an increase in customer shopping.

Wholesale generation revenues increased $49 million in the first nine months of 2007 due to higher market prices, partially offset by a 3.0% decrease in sales volume compared with the first nine months of 2006.

~~Changes in retail generation KWH sales and revenues by customer class in the first nine months of 2007 compared to the same period of 2006 are summarized in the following table:~~

~~Retail Generation KWH Sales~~	~~Increase~~ ~~(Decrease)~~

~~Residential~~		~~2.3~~	%
~~Commercial~~		~~1.6~~	%
~~Industrial~~		~~(7.0~~	)%
~~Net Increase in Generation Sales~~		~~1.6~~	%

Retail Generation Revenues

Increase

(In millions)

Residential $ 145
Commercial 100
Industrial 5
Increase in Generation Revenues

$
250

Distribution revenues increased in the first nine months of 2007 compared to the same period of 2006 due to higher composite unit prices and increased KWH deliveries, reflecting the weather impacts described above. The higher unit prices resulted from an NUGC rate increase effective in December 2006.

~~Changes in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables.~~

~~Distribution KWH Deliveries~~	~~Increase~~

~~Residential~~		~~2.3~~	%
~~Commercial~~		~~3.3~~	%
~~Industrial~~		~~1.1~~	%
~~Increase in Distribution Deliveries~~		~~2.6~~	%

~~110~~

Distribution Revenues

Increase

(In millions)
Residential $ 35
Commercial 38
Industrial 6
Increase in Distribution Revenues

$
79

The higher revenues for the first nine months of 2007 also included $20 million of increased revenues resulting from the August 2006 securitization of deferred costs associated with JCP&L’s BGS supply.

~~Expenses~~

~~Total expenses increased by $380 million in the first nine months of 2007 as compared to the same period of 2006. The following table presents changes from the prior year by expense category:~~

Expenses - Changes

Increase
(Decrease)

(In millions)
Purchased power costs $ 300
Other operating costs (9 )
Provision for depreciation 1
Amortization of regulatory assets 87
General Taxes 1
Net increase in expenses
$ 380

The increase in purchased power costs primarily reflected higher unit prices resulting from the June 2006 and June 2007 BGS auctions. Other operating costs decreased $9 million in the first nine months of 2007 primarily due to lower employee benefit costs. Amortization of regulatory assets increased $87 million in the first nine months of 2007 due to higher cost recovery associated with the December 2006 NUGC rate increase.

~~Other Expenses~~

Other expenses increased $9 million in the first nine months of 2007 from the same period in 2006 primarily due to interest expense associated with JCP&L’s $550 million issuance of Senior Notes in May 2007.

~~Legal Proceedings~~

~~New Accounting Standards and Interpretations~~

~~111~~

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2007

2006

2007

2006

(In thousands)

REVENUES:

Electric sales $ 391,083 $ 337,750 $ 1,087,460 $ 898,320
Gross receipts tax collections 19,524 18,431 55,146 51,293
Total revenues 410,607 356,181 1,142,606 949,613

EXPENSES:

Purchased power 209,842 184,508 584,249 487,465
Other operating costs 106,104 108,740 315,227 229,394
Provision for depreciation 11,154 10,197 31,969 31,390
Amortization of regulatory assets 36,853 33,560 101,965 89,277
Deferral of new regulatory assets (19,151 ) (44,213 ) (93,772 ) (89,794 )
General taxes 21,986 21,362 63,208 60,578
Total expenses 366,788 314,154 1,002,846 808,310

OPERATING INCOME
43,819 42,027 139,760 141,303

OTHER INCOME (EXPENSE):

Interest income 7,239 8,053 22,740 25,767
Miscellaneous income 1,366 1,477 3,973 5,881
Interest expense (13,291 ) (12,291 ) (38,471 ) (35,546 )
Capitalized interest 292 355 940 966
Total other expense (4,394 ) (2,406 ) (10,818 ) (2,932 )

INCOME BEFORE INCOME TAXES
39,425 39,621 128,942 138,371

INCOME TAXES
14,737 14,631 53,145 55,390

NET INCOME
24,688 24,990 75,797 82,981

OTHER COMPREHENSIVE INCOME (LOSS):

Pension and other postretirement benefits (1,452 ) - (4,357 ) -
Unrealized gain on derivative hedges 83 83 251 251
Other comprehensive income (loss) (1,369 ) 83 (4,106 ) 251
Income tax expense (benefit) related to other
comprehensive income (693 ) 34 (2,078 ) 104
Other comprehensive income (loss), net of tax (676 ) 49 (2,028 ) 147

TOTAL COMPREHENSIVE INCOME
$ 24,012 $ 25,039 $ 73,769 $ 83,128

The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of
these statements.

~~112~~

METROPOLITAN EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

September 30,

December 31,

2007

2006

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 126 $ 130
Receivables-
Customers (less accumulated provisions of $4,740,000 and $4,153,000,
respectively, for uncollectible accounts) 154,622 127,084
Associated companies 23,728 3,604
Other 18,043 8,107
Notes receivable from associated companies 34,620 31,109
Prepaid taxes 5,755 13,533
Other 1,976 1,424
238,870 184,991
UTILITY PLANT:

In service 1,976,453 1,920,563
Less - Accumulated provision for depreciation 755,018 739,719
1,221,435 1,180,844
Construction work in progress 21,124 18,466
1,242,559 1,199,310
OTHER PROPERTY AND INVESTMENTS:

Nuclear plant decommissioning trusts 290,349 269,777
Other 1,360 1,362
291,709 271,139
DEFERRED CHARGES AND OTHER ASSETS:

Goodwill 426,368 496,129
Regulatory assets 458,566 409,095
Pension assets 26,239 7,261
Other 38,653 46,354
949,826 958,839
$ 2,722,964 $ 2,614,279
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ - $ 50,000
Short-term borrowings-
Associated companies 254,826 141,501
Other 80,000 -
Accounts payable-
Associated companies 24,807 100,232
Other 55,186 59,077
Accrued taxes 9,033 11,300
Accrued interest 7,343 7,496
Other 26,960 22,825
458,155 392,431
CAPITALIZATION:

Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,500 shares outstanding 1,207,634 1,276,075
Accumulated other comprehensive loss (28,544 ) (26,516 )
Accumulated deficit (158,873 ) (234,620 )
Total common stockholder's equity 1,020,217 1,014,939
Long-term debt and other long-term obligations 542,100 542,009
1,562,317 1,556,948
NONCURRENT LIABILITIES:

Accumulated deferred income taxes 393,169 387,456
Accumulated deferred investment tax credits 8,623 9,244
Nuclear fuel disposal costs 43,038 41,459
Asset retirement obligations 158,302 151,107
Retirement benefits 15,830 19,522
Other 83,530 56,112
702,492 664,900
COMMITMENTS AND CONTINGENCIES (Note 10)

$ 2,722,964 $ 2,614,279

The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part
of these balance sheets.

~~113~~

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended

September 30,

2007

2006

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 75,797 $ 82,981
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 31,969 31,390
Amortization of regulatory assets 101,965 89,277
Deferred costs recoverable as regulatory assets (53,276 ) (53,406 )
Deferral of new regulatory assets (93,772 ) (89,794 )
Deferred income taxes and investment tax credits, net 20,514 27,895
Accrued compensation and retirement benefits (14,404 ) (6,007 )
Cash collateral 1,650 (21,500 )
Pension trust contribution (11,012 ) -
Decrease (increase) in operating assets-
Receivables (57,599 ) 27,680
Prepayments and other current assets 7,227 (8,247 )
Increase (decrease) in operating liabilities-
Accounts payable (79,316 ) (1,553 )
Accrued taxes 1,787 (10,451 )
Accrued interest (153 ) (308 )
Other 5,436 (1,777 )
Net cash provided from (used for) operating activities (63,187 ) 66,180

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Short-term borrowings, net 193,324 116,624
Equity contribution from parent 1,237 -
Redemptions and Repayments-
Long-term debt (50,000 ) (100,000 )
Dividend Payments-
Common Stock - (5,000 )
Net cash provided from financing activities 144,561 11,624

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (74,812 ) (65,332 )
Sales of investment securities held in trusts 153,943 146,841
Purchases of investment securities held in trusts (156,623 ) (153,953 )
Loans to associated companies, net (3,511 ) (4,853 )
Other (375 ) (494 )
Net cash used for investing activities (81,378 ) (77,791 )

Net increase (decrease) in cash and cash equivalents (4 ) 13
Cash and cash equivalents at beginning of period 130 120
Cash and cash equivalents at end of period $ 126 $ 133

The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these statements.

~~114~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of Metropolitan Edison Company:~~

We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~October 31, 2007~~

~~115~~

~~METROPOLITAN EDISON COMPANY~~

~~MANAGEMENT’S NARRATIVE~~

~~ANALYSIS OF RESULTS OF OPERATIONS~~

Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier.

~~Results of Operations~~

Net income for the first nine months of 2007 decreased to $76 million from $83 million in the first nine months of 2006. The decrease was primarily due to higher purchased power costs and other operating costs, partially offset by higher revenues.

~~Revenues~~

Revenues increased by $193 million, or 20.3%, in the first nine months of 2007 compared with the first nine months of 2006. This increase was primarily due to higher distribution revenues and wholesale generation revenues.

In the first nine months of 2007, retail generation revenues increased by $19 million primarily due to higher KWH sales in all customer sectors. The increase in retail generation revenues in the residential and commercial sectors primarily resulted from higher weather-related usage in the first nine months of 2007 as compared to the same period of 2006 (heating degree days increased by 17.1% and cooling degree days increased by 7.1%).

~~Increases in retail generation sales and revenues in the first nine months of 2007 compared to the same period of 2006 are summarized in the following tables:~~

~~Retail Generation KWH Sales~~	~~Increase~~

~~Residential~~		~~5.6~~	%
~~Commercial~~		~~4.0~~	%
~~Industrial~~		~~0.6~~	%
~~Increase in Retail Generation Sales~~		~~3.6~~	%

~~Retail Generation Revenues~~	~~Increase~~
	*~~(In millions)~~*
~~Residential~~	$	11
~~Commercial~~		8
~~Industrial~~		-
~~Increase in Retail Generation Revenues~~	$	19

Wholesale revenues increased by $107 million in the first nine months of 2007 compared with the same period of 2006 due to Met-Ed selling additional available power into the PJM market beginning in January 2007.

Revenues from distribution throughput increased by $55 million in the first nine months of 2007 compared to the same period in 2006. The increase was due to higher KWH deliveries, reflecting the effect of the weather discussed above, and an increase in composite unit prices resulting from the January 2007 PPUC authorization to increase transmission rates, partially offset by a decrease in distribution rates.

~~Increases in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the same period of 2006 are summarized in the following tables:~~

~~Distribution KWH Deliveries~~	~~Increase~~

~~Residential~~		~~5.6~~	%
~~Commercial~~		~~4.0~~	%
~~Industrial~~		~~0.2~~	%
~~Increase in Distribution Deliveries~~		~~3.5~~	%

~~116~~

~~Distribution Revenues~~	~~Increase~~
	*~~(In millions)~~*
~~Residential~~	$	38
~~Commercial~~		5
~~Industrial~~		12
~~Increase in Distribution Revenues~~	$	55

PJM transmission revenues increased by $18 million in the first nine months of 2007 as a result of higher transmission volumes and additional PJM auction revenue rights, compared to the prior year period. Met-Ed defers the difference between revenue from its transmission rider and transmission costs incurred, resulting in no material effect to current period earnings.

~~Expenses~~

~~Total expenses increased by $195 million in the first nine months of 2007 compared to the same period of 2006. The following table presents changes from the prior year by expense category:~~

Expenses – Changes

Increase
(Decrease)

(In millions)

Purchased power costs $ 97
Other operating costs 86
Amortization of regulatory assets 13
Deferral of new regulatory assets (4 )
General taxes 3
Net increase in expenses
$ 195

Purchased power costs increased in the first nine months of 2007 by $97 million due to higher volumes purchased to source higher generation sales, combined with higher composite unit costs. Other operating costs increased in the first nine months of 2007 primarily due to higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above ($83 million) and increased expenses ($3 million) related to Met-Ed’s customer assistance programs.

Amortization of regulatory assets increased in the first nine months of 2007 primarily due to the recovery (through Met-Ed’s transmission rider discussed above) of certain transmission costs deferred in 2006 and the amortization of the Saxton nuclear research facility’s decommissioning costs as authorized by the PPUC in January 2007. The deferral of new regulatory assets increased in the first nine months of 2007 primarily due to the deferral of previously expensed Saxton decommissioning costs of $15 million (see Legal Proceedings), partially offset by lower PJM transmission deferrals.

~~In the first nine months of 2007, general taxes increased primarily due to higher gross receipts taxes.~~

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

~~Legal Proceedings~~

~~New Accounting Standards and Interpretations~~

~~117~~

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2007

2006

2007

2006

(In thousands)

REVENUES:

Electric sales $ 336,798 $ 287,633 $ 991,769 $ 813,860
Gross receipts tax collections 16,637 15,787 48,989 46,311
Total revenues 353,435 303,420 1,040,758 860,171

EXPENSES:

Purchased power 203,247 165,921 588,583 474,437
Other operating costs 51,571 65,165 169,299 151,640
Provision for depreciation 12,566 11,828 36,678 36,269
Amortization of regulatory assets, net 20,861 3,825 32,648 19,804
General taxes 19,433 18,593 57,634 55,440
Total expenses 307,678 265,332 884,842 737,590

OPERATING INCOME
45,757 38,088 155,916 122,581

OTHER INCOME (EXPENSE):

Miscellaneous income 1,483 2,182 5,035 6,179
Interest expense (14,017 ) (11,840 ) (38,426 ) (33,975 )
Capitalized interest 194 363 737 1,132
Total other expense (12,340 ) (9,295 ) (32,654 ) (26,664 )

INCOME BEFORE INCOME TAXES
33,417 28,793 123,262 95,917

INCOME TAXES
10,387 10,733 49,025 39,251

NET INCOME
23,030 18,060 74,237 56,666

OTHER COMPREHENSIVE INCOME (LOSS):

Pension and other postretirement benefits (2,825 ) - (8,475 ) -
Unrealized gain on derivative hedges 16 17 49 49
Change in unrealized gain on available for sale securities 10 14 (6 ) (4 )
Other comprehensive income (loss) (2,799 ) 31 (8,432 ) 45
Income tax expense (benefit) related to other
comprehensive income (1,294 ) 13 (3,894 ) 20
Other comprehensive income (loss), net of tax (1,505 ) 18 (4,538 ) 25

TOTAL COMPREHENSIVE INCOME
$ 21,525 $ 18,078 $ 69,699 $ 56,691

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral
part of these statements.

~~118~~

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

September 30,

December 31,

2007

2006

(In thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ 38 $ 44
Receivables-
Customers (less accumulated provisions of $4,094,000 and $3,814,000
respectively, for uncollectible accounts) 138,007 126,639
Associated companies 21,872 49,728
Other 19,047 16,367
Notes receivable from associated companies 17,170 19,548
Prepaid taxes 7,268 3,016
Other 1,724 1,220
205,126 216,562
UTILITY PLANT:

In service 2,188,553 2,141,324
Less - Accumulated provision for depreciation 824,141 809,028
1,364,412 1,332,296
Construction work in progress 26,835 22,124
1,391,247 1,354,420
OTHER PROPERTY AND INVESTMENTS:

Nuclear plant decommissioning trusts 137,896 125,216
Non-utility generation trusts 147,745 99,814
Other 531 531
286,172 225,561
DEFERRED CHARGES AND OTHER ASSETS:

Goodwill 777,904 860,716
Pension assets 34,484 11,474
Other 34,371 36,059
846,759 908,249
$ 2,729,304 $ 2,704,792
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Short-term borrowings-
Associated companies $ 187,313 $ 199,231
Other 65,000 -
Accounts payable-
Associated companies 107,666 92,020
Other 46,283 47,629
Accrued taxes 3,091 11,670
Accrued interest 13,832 7,224
Other 24,481 21,178
447,666 378,952
CAPITALIZATION:

Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
4,427,577 and 5,290,596 shares outstanding, respectively 88,552 105,812
Other paid-in capital 925,229 1,189,434
Accumulated other comprehensive loss (11,731 ) (7,193 )
Retained earnings 39,195 90,005
Total common stockholder's equity 1,041,245 1,378,058
Long-term debt and other long-term obligations 777,020 477,304
1,818,265 1,855,362
NONCURRENT LIABILITIES:

Regulatory liabilities 77,441 96,151
Asset retirement obligations 80,589 76,924
Accumulated deferred income taxes 183,598 193,662
Retirement benefits 51,289 50,328
Other 70,456 53,413
463,373 470,478
COMMITMENTS AND CONTINGENCIES (Note 10)

$ 2,729,304 $ 2,704,792

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
integral part of these balance sheets.

~~119~~

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended

September 30,

2007

2006

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 74,237 $ 56,666
Adjustments to reconcile net income to net cash from operating activities
Provision for depreciation 36,678 36,269
Amortization of regulatory assets 43,601 40,854
Deferral of new regulatory assets (10,953 ) (21,050 )
Deferred costs recoverable as regulatory assets (54,228 ) (56,272 )
Deferred income taxes and investment tax credits, net 8,065 14,518
Accrued compensation and retirement benefits (16,032 ) 2,807
Cash collateral 50 -
Pension trust contribution (13,436 ) -
Decrease (increase) in operating assets
Receivables 13,809 22,719
Prepayments and other current assets (4,757 ) (2,977 )
Increase (decrease) in operating liabilities
Accounts payable 14,299 (15,555 )
Accrued taxes (6,191 ) (9,841 )
Accrued interest 6,608 5,468
Other 2,653 (2,188 )
Net cash provided from operating activities 94,403 71,418

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing
Long-Term Debt 297,149 -
Short-term borrowings, net 53,082 21,278
Equity contribution from parent 1,261 -
Redemptions and Repayments
Common Stock (200,000 ) -
Dividend Payments
Common Stock (125,000 ) (5,000 )
Net cash provided from financing activities 26,492 16,278

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (70,076 ) (81,228 )
Loan repayments from (loans to) associated companies, net 2,378 (2,976 )
Sales of investment securities held in trust 94,292 83,601
Purchases of investment securities held in trust (144,167 ) (83,601 )
Other, net (3,328 ) (3,480 )
Net cash used for investing activities (120,901 ) (87,684 )

Net increase (decrease) in cash and cash equivalents (6 ) 12
Cash and cash equivalents at beginning of period 44 35
Cash and cash equivalents at end of period $ 38 $ 47

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
integral part of these statements.

~~120~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of Pennsylvania Electric Company:~~

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~October 31, 2007~~

~~121~~

~~PENNSYLVANIA ELECTRIC COMPANY~~

~~MANAGEMENT’S NARRATIVE~~

~~ANALYSIS OF RESULTS OF OPERATIONS~~

~~Results of Operations~~

In the first nine months of 2007, net income increased to $74 million, compared to $57 million in the first nine months of 2006. The increase in net income was primarily due to higher revenues, partially offset by increased purchased power costs and other operating costs.

~~Revenues~~

Revenues increased by $181 million, or 21.0%, in the first nine months of 2007 compared to the same period last year. The increase was primarily due to higher distribution revenues and wholesale generation revenues.

Retail generation revenues increased $15 million for the first nine months of 2007 primarily due to higher KWH sales to all customer classes. The increase in retail generation revenues in the residential and commercial sectors was primarily impacted by weather in the first nine months of 2007 (heating degree days increased 11.0% and cooling degree days increased 14.1% as compared to the same time period of 2006).

~~Increases in retail generation sales and revenues in first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables:~~

~~Retail Generation KWH Sales~~	~~Increase~~

~~Residential~~		~~3.6~~	%
~~Commercial~~		~~3.6~~	%
~~Industrial~~		~~0.1~~	%
~~Increase in Retail Generation Sales~~		~~2.5~~	%

Retail Generation Revenues

Increase

(In millions)

Residential $ 6
Commercial 8
Industrial 1
Increase in Retail Generation Revenues

$
15

Wholesale revenues increased $123 million in the first nine months of 2007, compared with the same period of 2006 due to Penelec selling additional available power into the PJM market beginning in January 2007.

Revenues from distribution throughput increased $37 million in the first nine months of 2007 due to higher KWH deliveries to residential and commercial customers reflecting the effect of the weather discussed above and an increase in composite unit prices for residential and industrial customers resulting from a January 2007 PPUC authorization to increase transmission rates, partially offset by a decrease in distribution rates.

~~Changes in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the same period in 2006 are summarized in the following tables:~~

	~~Increase~~
~~Distribution KWH Deliveries~~	~~(Decrease)~~

~~Residential~~		~~3.6~~	%
~~Commercial~~		~~3.6~~	%
~~Industrial~~		~~(1.3~~	)%
~~Net Increase in Distribution Deliveries~~		~~1.9~~	%

~~122~~

Increase

Distribution Revenues

(Decrease)

(In millions)

Residential $ 37
Commercial (4 )
Industrial 4
Net Increase in Distribution Revenues

$
37

PJM transmission revenues increased by $6 million in the first nine months of 2007 compared to the same period in 2006 due to higher transmission volumes and additional PJM auction revenue rights in 2007. Penelec defers the difference between revenue from its transmission rider and transmission costs incurred, with no material effect to current period earnings.

~~Expenses~~

~~Total expenses increased by $147 million in the first nine months of 2007 compared with the same period in 2006. The following table presents changes from the prior year by expense category:~~

Expenses - Changes

Increase

(In millions)
Purchased power costs $ 114
Other operating costs 18
Amortization of regulatory assets, net 13
General taxes 2
Increase in Expenses
$ 147

Purchased power costs increased by $114 million, or 24.1% in the first nine months of 2007, compared to the same period of 2006. The increase was due primarily to higher volumes purchased to source higher retail and wholesale generation sales combined with higher composite unit costs. Other operating costs increased by $18 million in the first nine months of 2007 principally due to higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above.

Net amortization of regulatory assets increased in the first nine months of 2007 primarily due to the recovery (through Penelec’s transmission rider discussed above) of certain transmission costs deferred in 2006 and lower transmission cost deferrals in 2007, partially offset by the deferral of new regulatory assets for previously expensed decommissioning costs of $12 million associated with the Saxton nuclear research facility as authorized by the PPUC in January 2007 (see Legal Proceedings).

~~General taxes increased $2 million in the first nine months of 2007 as compared to 2006, primarily due to higher gross receipts taxes.~~

~~Legal Proceedings~~

~~New Accounting Standards and Interpretations~~

~~123~~

~~COMBINED MANAGEMENT’S DISCUSSION~~

~~AND ANALYSIS OF REGISTRANT SUBSIDIARIES~~

The following is a combined presentation of certain disclosures referenced in Management’s Narrative Analysis of Results of Operations of FES and the Companies. This information should be read in conjunction with (i) FES’ and the Companies’ respective Consolidated Financial Statements and Management’s Narrative Analysis of Results of Operations; (ii) the Notes to Consolidated Financial Statements as they relate to FES and the Companies; and (iii) the Companies’ respective 2006 Annual Reports on Form 10-K.

~~Regulatory Matters~~~~(Applicable to each of the Companies)~~

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

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

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

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

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

·	~~requiring corporate separation of regulated and unregulated business activities.~~

The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $227 million as of September 30, 2007 (JCP&L - $93 million, Met-Ed - $43 million and Penelec - $91 million). Regulatory assets not earning a current return will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets by company:

September 30,

December 31,

Increase

Regulatory Assets*

2007

2006

(Decrease)

(In millions)

OE $ 717 $ 741 $ (24 )
CEI 856 855 1
TE 215 248 (33 )
JCP&L 1,758 2,152 (394 )
Met-Ed 459 409 50
ATSI

42

36

6

Total
$
4,047

$
4,441

$
(394
)

*	~~Penelec had net regulatory liabilities of approximately $77 million~~ ~~and $96 million as of September 30, 2007 and December 31,~~ ~~2006, respectively. These net regulatory liabilities are included in~~ ~~Other Non-current Liabilities on the Consolidated Balance Sheets.~~

~~124~~

~~Ohio~~ ~~(Applicable to OE, CEI and TE)~~

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. 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. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2007 through 2010:

Several parties subsequently filed appeals to the Supreme Court of Ohio in connection with certain portions of the RCP approved by the PUCO. In its order, the PUCO authorized the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs, all such costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a 25-year period through distribution rates, which was expected to begin on January 1, 2009 for OE and TE, and approximately May 2009 for CEI. Through September 30, 2007, the deferred fuel costs, including interest, were $89 million, $61 million and $26 million for OE, CEI and TE, respectively.

~~125~~

~~Pennsylvania~~ ~~(Applicable to FES, Met-Ed, Penelec and Penn)~~

~~126~~

Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec 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. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. On June 19, 2007, initial briefs were filed and responsive briefs were filed through September 21, 2007. Reply briefs were filed on October 5, 2007. Oral arguments are expected to take place in late 2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the financial condition and results of operations of Met-Ed, Penelec and FirstEnergy.

~~127~~

On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service will be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. On September 28, 2007, Penn filed a Joint Petition for Settlement resolving all but one issue in the case. Briefs were also filed on September 28, 2007, on the unresolved issue of incremental uncollectible accounts expense. The settlement is either supported, or not opposed, by all parties. The PPUC is expected to act on the settlement and the unresolved issue in late November or early December 2007 for the initial RFP to take place in January 2008.

~~New Jersey~~ ~~(Applicable to JCP&L)~~

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2007, the accumulated deferred cost balance totaled approximately $330 million.

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated 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 New Jersey’s electricity needs with renewable energy resources by that date;~~

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

~~128~~

· ~~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;~~

·	~~Maintain unit prices for electricity to 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.~~

~~FERC Matters~~ ~~(Applicable~~(Applicable to FES and each of the Companies)

~~On November 18, 2004,~~SFAS 141(R) – “Business Combinations”

In December 2007, the ~~FERC~~FASB issued ~~an order~~SFAS 141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the ~~RTOR~~need for ~~transmission service between~~numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FES or any of the ~~MISO and PJM regions. The FERC~~Companies that close after January 1, 2009. In addition, the Standard also ~~ordered~~affects the ~~MISO, PJM~~accounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FES and the ~~transmission owners~~Companies are currently evaluating the impact of adopting this Standard on their financial statements.

SFAS 160 - “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”

In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within ~~MISO~~those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FES’ or the Companies’ financial statements.

SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”

In March 2008, the FASB issued SFAS 161, which enhances the current disclosure framework for derivative instruments and ~~PJM~~hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This disclosure better conveys the purpose of derivative use in terms of the risks that the entity is intending to ~~submit compliance filings containing~~manage. The FASB believes disclosing the fair values of derivative instruments and their gains and losses in a ~~SECA mechanism~~tabular format is designed to ~~recover lost RTOR revenues~~provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. Finally, this Statement requires cross-referencing within the footnotes, which is intended to help users of financial statements locate important information about derivative instruments. FES and the Companies are currently evaluating the impact of adopting this Standard on their financial statements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

FirstEnergy is a ~~16-month transition period from load serving entities. The FERC issued orders in 2005 setting~~diversified energy company that holds, directly or indirectly, all of the ~~SECA for hearing.~~outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and ~~FES participated~~its subsidiaries FGCO and NGC, and FESC.

FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.

These statements should be read in conjunction with the financial statements and notes included in the ~~FERC hearings held in May 2006 concerning~~combined Annual Report on Form 10-K for the ~~calculation~~year ended December 31, 2007 for FirstEnergy, FES and ~~imposition~~the Companies. The consolidated unaudited financial statements of FirstEnergy, FES and each of the ~~SECA charges.~~ Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 8) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.

The ~~presiding judge issued~~consolidated financial statements as of March 31, 2008 and for the three-month periods ended March 31, 2008 and 2007 have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated May 7, 2008) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.

2. EARNINGS PER SHARE

Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The pool of stock-based compensation tax benefits is calculated in accordance with SFAS 123(R). On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an accelerated share repurchase program at an initial 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.price of approximately $900 million. A final ~~order could be issued by the FERC~~purchase price adjustment of $51 million was settled in ~~the fourth quarter~~cash on December 13, 2007. The following table reconciles basic and diluted earnings per share of ~~2007.~~common stock:

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, BG&E and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. Hearings were held and numerous parties appeared and litigated various issues; including AEP, which filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. At the conclusion of the hearings, the ALJ issued an initial decision adopting 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. Numerous parties, including FirstEnergy, submitted briefs opposing the ALJ’s decision and recommendations. On April 19, 2007, the FERC issued an order rejecting the ALJ’s findings and recommendations in nearly every respect. The FERC found that the PJM transmission owners’ existing “license plate” rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be socialized throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. Nevertheless, the FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

Reconciliation of Basic and Diluted		Three Months Ended March 31,
Earnings per Share of Common Stock		2008		2007
	(In millions, except per share amounts)
Net income		$	276	$	290

Average shares of common stock outstanding – Basic			304		314
Assumed exercise of dilutive stock options and awards			3		2
Average shares of common stock outstanding – Dilutive			307		316

Basic earnings per share of common stock		$	0.91	$	0.92
Diluted earnings per share of common stock		$	0.90	$	0.92

~~129~~95

~~New FERC Transmission Rate Design Filings~~3. DIVESTITURES AND DISCONTINUED OPERATIONS

On ~~August~~March 7, 2008, FirstEnergy sold certain telecommunication assets, resulting in a net after-tax gain of $19.3 million. As a result of the sale, FirstEnergy adjusted goodwill by $1 million for the former GPU companies due to the realization of tax benefits that had been reserved in purchase accounting. The sale of assets did not meet the criteria for classification as discontinued operations as of March 31, 2008.

4. FAIR VALUE MEASURES

Effective January 1, ~~2007,~~2008, FirstEnergy adopted SFAS 157, which provides a ~~number~~framework for measuring fair value under GAAP and, among other things, requires enhanced disclosures about assets and liabilities recognized at fair value. FirstEnergy also adopted SFAS 159 on January 1, 2008, which provides the option to measure certain financial assets and financial liabilities at fair value. FirstEnergy has analyzed its financial assets and financial liabilities within the scope of ~~filings were made with~~SFAS 159 and, as of March 31, 2008, has elected not to record eligible assets and liabilities at fair value.

As defined in SFAS 157, fair value is the ~~FERC by transmission owning utilities~~price that would be received for an asset or paid to transfer a liability (exit price) in the ~~MISO~~principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and ~~PJM footprint~~the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that ~~could affect~~are held in various trusts.

Level 2 – Pricing inputs are either directly or indirectly observable in the ~~transmission rates paid~~market as of the reporting date, other than quoted prices in active markets included in Level 1. FirstEnergy’s Level 2 consists primarily of investments in debt securities held in various trusts and commodity forwards. Additionally, Level 2 includes those financial instruments that are valued using models or other valuation methodologies based on assumptions that are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Instruments in this category include non-exchange-traded derivatives such as forwards and certain interest rate swaps.

Level 3 – Pricing inputs include inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. FirstEnergy develops its view of the future market price of key commodities through a combination of market observation and assessment (generally for the short term) and fundamental modeling (generally for the longer term). Key fundamental electricity model inputs are generally directly observable in the market or derived from publicly available historic and forecast data. Some key inputs reflect forecasts published by industry leading consultants who generally employ similar fundamental modeling approaches. Fundamental model inputs and results, as well as the selection of consultants, reflect the consensus of appropriate FirstEnergy management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. FirstEnergy’s ~~operating companies and FES.~~Level 3 instruments consist of NUG contracts.

FirstEnergy ~~joined~~utilizes market data and assumptions that market participants would use in ~~a filing made by~~pricing the ~~MISO transmission owners that would maintain~~asset or liability, including assumptions about risk and the ~~existing “license plate” rates~~risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. FirstEnergy primarily applies the market approach for ~~transmission service within MISO provided over existing transmission facilities.~~recurring fair value measurements using the best information available. Accordingly, FirstEnergy ~~also joined in a filing made by both~~maximizes the ~~MISO~~use of observable inputs and ~~PJM transmission owners proposing to continue~~minimizes the ~~elimination~~use of transmission rates associated with service over existing transmission facilities between MISO and PJM. If adopted by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint be maintained (known as the RECB Process). Each of these filings was supported by the majority of transmission owners in either MISO or PJM, as applicable.unobservable inputs.

The ~~Midwest Stand-Alone Transmission Companies made a filing under Section 205~~following table sets forth FirstEnergy’s financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of March 31, 2008. As required by SFAS 157, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the ~~Federal Power Act requesting that 100%~~significance of the cost of new qualifying 345 kV and higher transmission facilities be spread throughout the entire MISO footprint. Further, Indianapolis Power and Light Company separately moved the FERC to reopen the record to address the cost allocation for the RECB Process. If either proposal is adopted by the FERC, it could shift a ~~greater portion of the cost of new 345 kV and higher transmission facilities~~particular input to the ~~FirstEnergy footprint in MISO,~~fair value measurement requires judgment and ~~increase~~may affect the ~~transmission rates paid by load-serving FirstEnergy affiliates in MISO.~~valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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

~~130~~96

~~MISO’s previous filing~~

	March 31, 2008
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
	(In millions)
Assets:
Derivatives	$	4	$	98	$	-	$	102
Nuclear decommissioning trusts(1)		1,070		953		-		2,023
Other investments(2)		21		303		-		324
Total	$	1,095	$	1,354	$	-	$	2,449

Liabilities:
Derivatives	$	-	$	98	$	-	$	98
NUG contracts(3)		-		-		682		682
Total	$	-	$	98	$	682	$	780

(1)

Balance excludes $2 million of receivables, payables and accrued income.

(2)

Excludes $318 million of the cash surrender value of life insurance contracts.

(3)

NUG contracts are completely offset by regulatory assets.

The determination of the above fair value measures takes into consideration various factors required under SFAS 157. These factors include the credit standing of the counterparties involved, the impact of credit enhancements (such as cash deposits, LOCs and priority interests) and the impact of nonperformance risk.

Exchange-traded derivative contracts, which include some futures and options, are generally based on unadjusted quoted market prices in active markets and are classified within Level 1. Forwards, options and swap contracts that are not exchange-traded are classified as Level 2 as the fair values of these items are based on ICE quotes or market transactions in the OTC markets. In addition, complex or longer term structured transactions can introduce the need for internally-developed model inputs that may not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is classified as Level 3.

Nuclear decommissioning trusts consist of equity securities listed on active exchanges classified as Level 1 and various debt securities and collective trusts classified as Level 2. Other investments represent the NUG trusts, spent nuclear fuel trusts and rabbi trust investments, which primarily consist of various debt securities and collective trusts classified as Level 2.

The following table sets forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2008 (in millions):

Balance as of January 1, 2008	$	750
Realized and unrealized gains (losses)(1)		(58	)
Purchases, sales, issuances and settlements, net(1)		(10	)
Net transfers to (from) Level 3		-
Balance as of March 31, 2008	$	682

Change in unrealized gains (losses) relating to
instruments held as of March 31, 2008	$	(58	)

(1) Changes in the fair value of NUG contracts are completely offset by regulatory assets and do not impact earnings.

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

5. DERIVATIVE INSTRUMENTS

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

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchases and normal sales criteria. Derivatives that meet those criteria are accounted for at cost. The changes in the fair value of derivative instruments that do not meet the normal purchases and normal sales criteria are recorded as other expense, as AOCL, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness. FirstEnergy does not offset fair value for the right to reclaim collateral or the obligation to return collateral.

The net deferred losses of $84 million included in AOCL as of March 31, 2008, for derivative hedging activity, as compared to $75 million as of December 31, 2007, resulted from a net $21 million increase related to current hedging activity and a $12 million decrease due to net hedge losses reclassified to earnings during the three months ended March 31, 2008. Based on current estimates, approximately $19 million (after tax) of the net deferred losses on derivative instruments in AOCL as of March 31, 2008 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.

FirstEnergy has entered into swaps that have been designated as fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. As of March 31, 2008, FirstEnergy had interest rate swaps with an ~~Ancillary Services~~aggregate notional value of $250 million and a fair value of $5 million.

During 2007 and the first three months of 2008, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated issuance of variable-rate, short-term debt and fixed-rate, long-term debt securities by one or more of its subsidiaries as outstanding debt matures during 2008 and 2009. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury and LIBOR rates between the date of hedge inception and the date of the debt issuance. During the first three months of 2008, FirstEnergy terminated swaps with a notional value of $300 million and entered into swaps with a notional value of $500 million. FirstEnergy paid $18 million related to the terminations, $1 million of which was deemed ineffective and recognized in current period earnings. FirstEnergy will recognize the remaining $17 million loss over the life of the associated future debt. As of March 31, 2008, FirstEnergy had forward swaps with an aggregate notional amount of $600 million and a fair value of $(8) million.

6. ASSET RETIREMENT OBLIGATIONS

The ARO liability of $1.3 billion as of March 31, 2008 is primarily related to the future nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of March 31, 2008, the fair value of the decommissioning trust assets was approximately $2.0 billion.

The following tables analyze changes to the ARO balance during the first quarters of 2008 and 2007, respectively.

ARO Reconciliation	FirstEnergy		FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Balance, January 1, 2008	$	1,267	$	810	$	94	$	2	$	28	$	90	$	161	$	82
Liabilities incurred		-		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-		-
Accretion		20		14		1		-		1		1		2		1
Revisions in estimated cash flows		-		-		-		-		-		-		-		-
Balance, March 31, 2008	$	1,287	$	824	$	95	$	2	$	29	$	91	$	163	$	83

Balance, January 1, 2007	$	1,190	$	760	$	88	$	2	$	27	$	84	$	151	$	77
Liabilities incurred		-		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-		-
Accretion		18		12		1		-		-		2		2		1
Revisions in estimated cash flows		-		-		-		-		-		-		-		-
Balance, March 31, 2007	$	1,208	$	772	$	89	$	2	$	27	$	86	$	153	$	78

7. PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees and those of its subsidiaries. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market ~~was rejected without prejudice~~value as of December 31, 2007. FirstEnergy also provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

The components of FirstEnergy's net periodic pension cost and other postretirement benefit cost (including amounts capitalized) for the three months ended March 31, 2008 and 2007, consisted of the following:

	Pension Benefits						Other Postretirement Benefits
	2008			2007			2008			2007
	(In millions)
Service cost	$	21		$	21		$	5		$	5
Interest cost		72			71			18			17
Expected return on plan assets		(115	)		(112	)		(13	)		(13	)
Amortization of prior service cost		2			2			(37	)		(37	)
Recognized net actuarial loss		1			10			12			12
Net periodic cost (credit)	$	(19	)	$	(8)		$	(15	)	$	(16	)

Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net periodic pension costs and net periodic postretirement benefit costs (including amounts capitalized) recognized by ~~FERC on June 22,~~each of the Companies for the three months ended March 31, 2008 and 2007 ~~subject to MISO making certain modifications in its filing. FirstEnergy believes that MISO’s September 14 filing generally~~were as follows:

	Pension Benefit Cost (Credit)						Other Postretirement Benefit Cost (Credit)
	2008			2007			2008			2007
	(In millions)
FES	$	4		$	-		$	(2	)	$	-
OE		(7	)		(4	)		(2	)		(3	)
CEI		(1	)		-			1			1
TE		(1	)		-			1			1
JCP&L		(4	)		(2	)		(4	)		(4	)
Met-Ed		(3	)		(2	)		(3	)		(2	)
Penelec		(3	)		(3	)		(3	)		(3	)
Other FirstEnergy subsidiaries		(4	)		3			(3	)		(6	)
	$	(19	)	$	(8	)	$	(15	)	$	(16	)

8. VARIABLE INTEREST ENTITIES

FIN 46R addresses the ~~FERC’s directives.~~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 ~~supports~~and its subsidiaries consolidate VIEs when they are determined to be the ~~proposal~~VIE's primary beneficiary as defined by FIN 46R.

Trusts

FirstEnergy’s consolidated financial statements include PNBV and Shippingport, VIEs created in 1996 and 1997, respectively, to ~~establish markets for Ancillary Services~~refinance debt originally issued in connection with sale and ~~consolidate existing balancing areas, but filed objections on specific aspects~~leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.

PNBV was established to purchase a portion of the ~~MISO proposal. Interventions~~lease obligation bonds issued in connection with OE’s 1987 sale and ~~protests~~leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to ~~MISO’s filing were made~~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 ~~FERC on October 15, 2007.~~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.

~~Order No. 890 on Open Access Transmission Tariffs~~

~~Environmental Matters~~Loss Contingencies

FES and the Ohio Companies ~~accrue~~are exposed to losses under their applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments are made. The following table shows each company’s net exposure to loss based upon the casualty value provisions mentioned above as of March 31, 2008:

	Maximum Exposure		Discounted Lease Payments, net		Net Exposure
	(in millions)
FES	$	1,364	$	1,216	$	148
OE	819		628		191
CEI	782		77		705
TE	782		457		325

In October 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. FGCO assumed all of CEI’s and TE’s obligations arising under those leases. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCO’s leasehold interests under its July 2007 Bruce Mansfield Unit 1 sale and leaseback transaction to a newly formed wholly-owned subsidiary in December 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE will remain primarily liable on the 1987 leases and related agreements as to the lessors and other parties to the agreements. FGCO remains primarily liable on the 2007 leases and related agreements, and FES remains primarily liable as a guarantor under the related 2007 guarantees, as to the lessors and other parties to the respective agreements. These assignments terminate automatically upon the termination of the underlying leases.

On March 3, 2008, notice was given to the nine owner trusts that are lessors under sale and leaseback transactions, originally entered into by TE in 1987, that NGC would acquire the related 18.26% undivided interest in Beaver Valley Unit 2 through the exercise of the periodic purchase option provided for in the applicable facility leases. The purchase price to be paid by NGC for the undivided interest will be equal to the higher of a specified casualty value under the applicable facility leases (approximately $239 million in the aggregate for the equity portion of all nine facility leases) and the fair market sales value of such undivided interests. Determination of the fair market sales value may become subject to an appraisal procedure provided for in the lease documentation. An additional payment of approximately $236 million would be required to prepay in full the outstanding principal of, and accrued but unpaid interest on, the lessor notes of the nine owner trusts. Alternatively, this amount would not be paid as part of the aggregate purchase price if the lessor notes are instead assumed at the time of the exercise of the option. If NGC determines to prepay the notes, it is possible that the proceeds from such prepayment may not be sufficient to pay the principal of, and interest on, the bonds as they become due. If that is the case, NGC would provide a mechanism to address any such potential shortfall in a timely manner.

100

Power Purchase Agreements

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

Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it may incur for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs from these entities during the three months ended March 31, 2008 and 2007 are shown in the following table:

	Three Months Ended
	March 31,
	2008		2007
	(In millions)
JCP&L	$	19	$	20
Met-Ed		16		15
Penelec		8		8
	$	43	$	43

Transition Bonds

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of March 31, 2008, $391 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.

9. INCOME TAXES

101

As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits was $268 million. FirstEnergy recorded a $2.7 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate upon recognition. The majority of items that would not have affected the effective tax rate would be purchase accounting adjustments to goodwill upon recognition. During the first three months of 2008 and 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of March 31, 2008, FirstEnergy expects that it is reasonably possible that $8 million of the unrecognized benefits will be resolved within the next twelve months and is included in the caption “accrued taxes,” with the remaining $263 million included in the caption “other non-current liabilities” on the Consolidated Balance Sheets.

FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. The net amount of interest accrued as of March 31, 2008 was $57 million, as compared to $53 million as of December 31, 2007. During the first three months of 2008 and 2007, there were no material changes to the amount of interest accrued.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2007. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audits for the years 2004-2006 are expected to close before December 2008, but management anticipates certain items to be under appeal. The IRS began auditing the year 2007 in February 2007 and year 2008 in February 2008 under its Compliance Assurance Process experimental program. Neither audit is expected to close before December 2008. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

10. COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A) GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of March 31, 2008, outstanding guarantees and other assurances aggregated approximately $4.4 billion, consisting of parental guarantees - $0.9 billion, subsidiaries’ guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $0.7 billion.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4 billion (included in the $0.9 billion discussed above) as of March 31, 2008 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of March 31, 2008, FirstEnergy's maximum exposure under these collateral provisions was $440 million.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $66 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $2 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 ($19 million as of March 31, 2008), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

102

In July 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.

(B)	ENVIRONMENTAL MATTERS

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

Clean Air Act Compliance~~(Applicable to FES)~~

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

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the ~~Clean Air Act. FES~~CAA. FirstEnergy has disputed those alleged violations based on its ~~Clean Air Act~~CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.

~~FES~~FirstEnergy complies with SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. 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 ~~FES'~~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. ~~FES~~FirstEnergy believes its facilities are also complying with the NO_X budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

~~131~~103

National Ambient Air Quality Standards~~(Applicable to FES)~~

~~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 ~~allowed each affected state until 2006 to develop implementing regulations to achieve additional~~requires reductions of NO_X and SO₂ emissions in two phases (Phase I in 2009 for NO_X, 2010 for SO₂ and Phase II in 2015 for both NO_X and SO₂). ~~FES’~~FirstEnergy's Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO₂ and NO_X emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on NO_X emissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. 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. CAIR has been challenged in the United States Court of Appeals for the District of Columbia. The future cost of compliance with these regulations may be substantial and ~~will~~may depend on the outcome of this litigation and how ~~they are~~CAIR is ultimately ~~implemented by the states in which FES operates affected facilities.~~implemented.

Mercury Emissions~~(Applicable to FES)~~

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,~~phases; initially, capping national mercury emissions ~~will be capped nationally~~ at 38 tons by 2010 (as a "co-benefit" from implementation of SO₂ 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~~ and 15 tons per year by 2018. ~~However, the final rules give~~Several states ~~substantial discretion in developing rules to implement these programs. In addition, both the CAIR~~ and environmental groups appealed the CAMR ~~have been challenged in~~to the United States Court of Appeals for the District of Columbia. ~~FES'~~On February 8, 2008, the court vacated the CAMR ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA must now seek further judicial review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with ~~these~~mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately ~~implemented by the states in which FES operates affected facilities.~~implemented.

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. FES 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, FES will be disadvantaged if these model rules were implemented as proposed because FES’ 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. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, ~~FES’~~FirstEnergy’s only Pennsylvania coal-fired ~~Pennsylvania~~ power plant, until 2015, if at all.

W. H. Sammis Plant~~(Applicable to FES, OE and Penn)~~

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NO_X and SO₂ emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. 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 ~~settlement agreement~~consent decree are currently estimated to be ~~$1.7~~$1.3 billion for ~~2007 through 2011~~2008-2012 ($~~400~~650 million of which is expected to be spent during ~~2007,~~2008, with the largest portion of the remaining ~~$1.3 billion~~$650 million expected to be spent in ~~2008~~2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

~~132~~104

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

Climate Change~~(Applicable to FES)~~

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

Clean Water Act~~(Applicable to FES)~~

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality ~~when~~(when aquatic organisms are pinned against screens or other parts of a cooling water intake ~~system,~~system) and entrainment ~~which~~(which occurs when aquatic life is drawn into a facility's cooling water ~~system.~~system). On January 26, 2007, the ~~federal~~United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. ~~FES~~On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review certain aspects of the Second Circuit’s decision. FirstEnergy is ~~evaluating~~studying various control options and their costs and effectiveness. Depending on the ~~outcome~~results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future ~~cost~~costs of compliance with these standards may require material capital expenditures.

Regulation of Hazardous Waste~~(Applicable to FES and each of the Companies)~~

~~133~~105

~~Other Legal Proceedings~~(C) OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation~~(Applicable to FES and each of the Companies)~~

~~134~~106

FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those 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. Two 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 cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and AEP, as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. 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. The four cases remaining were consolidated for hearing by the PUCO in an order dated March 7, 2006. In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled 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 January 8, 2008.

~~135~~

Nuclear Plant Matters~~(Applicable to FES)~~

Other Legal Matters~~(Applicable~~

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

~~New Accounting Standards and Interpretations~~~~(Applicable to FES and each of the Companies)~~

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11. REGULATORY MATTERS

~~SFAS 157 – “Fair Value Measurements”~~(A) RELIABILITY INITIATIVES

In ~~September~~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. The proposed enhancements were divided into two groups: enhancements that were to be completed in 2004; and enhancements that were to be completed after 2004. In 2004, FirstEnergy completed all of the enhancements that were recommended for completion in 2004. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU performed a review of JCP&L’s service reliability. On June 9, 2004, the NJBPU approved a stipulation that addresses a third-party consultant’s recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation incorporates the consultant’s focused audit of, and recommendations regarding, JCP&L’s Planning and Operations and Maintenance programs and practices. On June 1, 2005, the consultant completed his work and issued his final report to the NJBPU. On July 14, 2006, JCP&L filed a comprehensive response to the ~~FASB issued SFAS 157~~consultant’s report with the NJBPU. JCP&L will complete the remaining substantive work described in the stipulation in 2008. JCP&L continues to file compliance reports with the NJBPU reflecting JCP&L’s activities associated with implementing the stipulation.

FirstEnergy believes that ~~establishes how companies should measure fair value when they are required~~it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that NERC, ReliabilityFirst and the FERC will continue 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,refine existing reliability standards as well as ~~the inclusion of an adjustment for risk, restrictions~~to develop and ~~credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective for~~adopt new reliability standards. The financial ~~statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FES and the Companies are currently evaluating the~~ impact of complying with new or amended standards cannot be determined at this ~~Statement~~time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on ~~their~~FirstEnergy’s part to comply with the reliability standards for its bulk power system could have a material adverse effect on its financial ~~statements.~~condition, results of operations and cash flows.

~~136~~108

(B) OHIO

On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007 the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider, with alternative options for the recovery period ranging from five to twenty-five years. This second application is currently pending before the PUCO and a hearing has been set for July 15, 2008.

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·	automatic recovery of prudently incurred fuel, purchased power, emission allowance costs and federally mandated energy taxes;

~~SFAS 159 – “The Fair Value Option~~
· construction work in progress for ~~Financial Assets~~costs of constructing an electric generating facility or environmental expenditure for any electric generating facility;

·	costs of an electric generating facility;

·	terms related to customer shopping, bypassability, standby, back-up and ~~Financial Liabilities – Including an amendment~~default service;

·	accounting for deferrals related to stabilizing retail electric service;

·	automatic increases or decreases in standard service offer price;

·	phase-in and securitization;

·	transmission service and related costs;

·	distribution service and related costs; and

·	economic development and energy efficiency.

(C) PENNSYLVANIA

110

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.

111

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy. The final form of this pending legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

(D) NEW JERSEY

On April 17, 2008, a draft EMP was released for public comment. The draft EMP establishes four major goals:

·	maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020;

·	reduce peak demand for electricity by 5,700 MW by 2020 (amounting to about a 22% reduction in projected demand);

112

·	meet 22.5% of ~~FASB Statement No. 115”~~the state’s electricity needs with renewable energy by 2020; and

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

On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments that were submitted in September and October 2007. Final regulations (effective upon publication) were published in the New Jersey Register March 17, 2008. Upon preliminary review of the new regulations, FirstEnergy does not expect a material impact on its operations or those of JCP&L.

(E) FERC MATTERS

Transmission Service between MISO and PJM

PJM Transmission Rate Design

113

Post Transition Period Rate Design

Distribution of MISO Network Service Revenues

MISO Ancillary Services Market and Balancing Area Consolidation

114

Duquesne’s Request to Withdraw from PJM

MISO Resource Adequacy Proposal

Organized Wholesale Power Markets

115

12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 141(R) – “Business Combinations”

In ~~February~~December 2007, the FASB issued SFAS ~~159,~~141(R), which ~~provides companies with an option~~requires the acquiring entity in a business combination to ~~report selected financial~~recognize all the assets acquired and liabilities atassumed in the transaction; establishes the acquisition-date fair ~~value. This Statement~~value as the measurement objective for all assets acquired and liabilities assumed; and requires ~~companies~~the acquirer to ~~provide additional information that will help~~disclose to investors and other users all of ~~financial statements~~the information they need to ~~more easily~~evaluate and understand the nature and financial effect of the ~~company’s choice~~business combination. SFAS 141(R) attempts to ~~use fair value~~reduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FirstEnergy is currently evaluating the impact of adopting this Standard on its ~~earnings. The Standard also requires companies to display~~financial statements.

SFAS 160 - “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”

In December 2007, the ~~fair value~~FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of ~~those assets and liabilities for which~~a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the ~~company has chosen to use fair value on~~consolidated entity that should be reported as equity in the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157~~and SFAS 107~~. consolidated financial statements. This Statement is effective for ~~financial statements issued for~~ fiscal years, ~~beginning after November 15, 2007,~~ and interim periods within those ~~years. FES and the Companies are currently evaluating the impact of this Statement on their financial statements.~~

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

In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R). The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to additional paid-in capital (APIC). This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement. The consensus is effective for income tax benefits of dividends declared during fiscal years, beginning on or after December 15, ~~2007. EITF 06-11~~2008. Early adoption is prohibited. The Statement is not expected to have a material impact on ~~FES’ or the Companies’~~FirstEnergy’s financial statements.

~~FSP FIN 39-1 – “Amendment of FASB Interpretation No. 39”~~
SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”

In ~~April 2007,~~March 2008, the FASB issued ~~Staff Position (FSP) FIN 39-1,~~SFAS 161, which ~~permits an entity~~requires enhancements to ~~offset fair value amounts recognized for~~ the ~~right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized~~current disclosure framework for derivative instruments and hedging activities. The Statement requires that ~~have been offset under~~objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This disclosure is intended to better convey the ~~same master netting arrangement as~~purpose of derivatives use in terms of the risks that the entity is intending to manage. The FASB believes disclosing the fair values of derivative instruments and their gains and losses in a tabular format is designed to provide a more complete picture of the location in an entity’s financial statements of both the derivative ~~instruments. This FSP~~positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is ~~effective for fiscal years beginning after November 15, 2007, with early application permitted. The effects~~designed to provide financial statement users information on the potential effect on an entity’s liquidity from using derivatives. Finally, this Statement requires cross-referencing within the footnotes, which is intended to help users of ~~applying the guidance in this FSP should be recognized as a retrospective change in accounting principle for all~~ financial statements ~~presented. FES and the Companies are~~locate important information about derivative instruments. FirstEnergy is currently evaluating the impact of adopting this ~~FSP~~Standard on ~~their~~its financial ~~statements but it is not expected to have a material impact.~~statements.

13. SEGMENT INFORMATION

FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The “Other” segment primarily consists of telecommunications services. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”

The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. Its revenues are primarily derived from the delivery of electricity, cost recovery of regulatory assets and default service electric generation sales to non-shopping customers in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under partial requirements purchased power agreements and from non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.

The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive electric sales primarily in Ohio, Pennsylvania, Maryland and Michigan, owns or leases and operates FirstEnergy’s generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from the affiliated company PSA sales and the non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment’s customers. The segment’s internal revenues represent the affiliated company PSA sales.

~~137~~116

The Ohio transitional generation services segment represents the regulated generation commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect the purchase of electricity from the competitive energy services segment through full-requirements PSA arrangements, the deferral and amortization of certain fuel costs authorized for recovery by the energy delivery services segment and the net MISO transmission revenues and expenses related to the delivery of generation load. This segment’s total assets consist of accounts receivable for generation revenues from retail customers.

Segment Financial Information
Ohio
Energy Competitive Transitional
Delivery Energy Generation Reconciling
Three Months Ended Services Services Services Other Adjustments Consolidated
(In millions)
March 31, 2008
External revenues $ 2,212 $ 329 $ 707 $ 40 $ (11 ) $ 3,277
Internal revenues - 776 - - (776 ) -
Total revenues 2,212 1,105 707 40 (787 ) 3,277
Depreciation and amortization 255 53 4 - 5 317
Investment income 45 (6 ) 1 - (23 ) 17
Net interest charges 103 27 - - 41 171
Income taxes 119 58 15 14 (19 ) 187
Net income 179 87 23 22 (35 ) 276
Total assets 23,211 8,108 257 281 558 32,415
Total goodwill 5,582 24 - - - 5,606
Property additions 255 462 - 12 (18 ) 711

March 31, 2007
External revenues $ 2,040 $ 321 $ 619 $ 12 $ (19 ) $ 2,973
Internal revenues - 714 - - (714 ) -
Total revenues 2,040 1,035 619 12 (733 ) 2,973
Depreciation and amortization 220 51 (15 ) 1 6 263
Investment income 70 3 1 - (41 ) 33
Net interest charges 107 49 1 2 21 180
Income taxes 148 65 15 5 (33 ) 200
Net income 218 98 24 1 (51 ) 290
Total assets 23,526 7,089 246 254 675 31,790
Total goodwill 5,874 24 - - - 5,898
Property additions 155 124 - 1 16 296

14. SUPPLEMENTAL GUARANTOR INFORMATION

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.

The consolidating statements of income for the three months ended March 31, 2008 and 2007, consolidating balance sheets as of March 31, 2008 and December 31, 2007 and condensed consolidating statements of cash flows for the three months ended March 31, 2008 and 2007 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

117

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended March 31, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 1,099,848 $ 567,701 $ 325,684 $ (894,117 ) $ 1,099,116

EXPENSES:
Fuel 2,138 291,239 28,312 - 321,689
Purchased power from non-affiliates 206,724 - - - 206,724
Purchased power from affiliates 891,979 2,138 25,485 (894,117 ) 25,485
Other operating expenses 37,596 107,167 139,595 12,188 296,546
Provision for depreciation 307 26,599 24,194 (1,358 ) 49,742
General taxes 5,415 11,570 6,212 - 23,197
Total expenses 1,144,159 438,713 223,798 (883,287 ) 923,383

OPERATING INCOME (LOSS) (44,311 ) 128,988 101,886 (10,830 ) 175,733

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees 121,725 (1,208 ) (6,537 ) (116,884 ) (2,904 )
Interest expense to affiliates (82 ) (5,289 ) (1,839 ) - (7,210 )
Interest expense - other (3,978 ) (25,968 ) (11,018 ) 16,429 (24,535 )
Capitalized interest 21 6,228 414 - 6,663
Total other income (expense) 117,686 (26,237 ) (18,980 ) (100,455 ) (27,986 )

INCOME BEFORE INCOME TAXES 73,375 102,751 82,906 (111,285 ) 147,747

INCOME TAXES (BENEFIT) (16,609 ) 39,285 32,764 2,323 57,763

NET INCOME $ 89,984 $ 63,466 $ 50,142 $ (113,608 ) $ 89,984
118

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended March 31, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 1,019,387 $ 551,355 $ 234,091 $ (786,540 ) $ 1,018,293

EXPENSES:
Fuel 2,367 201,231 29,937 - 233,535
Purchased power from non-affiliates 186,203 2,367 - (2,367 ) 186,203
Purchased power from affiliates 784,172 59,069 17,415 (784,173 ) 76,483
Other operating expenses 51,249 99,095 113,252 - 263,596
Provision for depreciation 453 24,936 22,621 - 48,010
General taxes 4,934 10,568 6,216 - 21,718
Total expenses 1,029,378 397,266 189,441 (786,540 ) 829,545

OPERATING INCOME (LOSS) (9,991 ) 154,089 44,650 - 188,748

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees 113,948 916 5,200 (100,332 ) 19,732
Interest expense to affiliates - (24,331 ) (5,115 ) - (29,446 )
Interest expense - other (1,385 ) (6,760 ) (9,213 ) - (17,358 )
Capitalized interest 5 2,099 1,105 - 3,209
Total other income (expense) 112,568 (28,076 ) (8,023 ) (100,332 ) (23,863 )

INCOME BEFORE INCOME TAXES 102,577 126,013 36,627 (100,332 ) 164,885

INCOME TAXES 73 49,289 13,019 - 62,381

NET INCOME $ 102,504 $ 76,724 $ 23,608 $ (100,332 ) $ 102,504

119

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of March 31, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents $ 2 $ - $ - $ - $ 2
Receivables-
Customers 125,116 - - - 125,116
Associated companies 285,350 231,049 96,852 (295,511 ) 317,740
Other 1,174 1,050 - 2,224
Notes receivable from associated companies 668,376 - 69,011 - 737,387
Materials and supplies, at average cost 2,849 264,501 207,275 - 474,625
Prepayments and other 107,798 26,208 1,728 - 135,734
1,190,665 522,808 374,866 (295,511 ) 1,792,828

PROPERTY, PLANT AND EQUIPMENT:
In service 35,302 5,359,381 3,700,973 (391,896 ) 8,703,760
Less - Accumulated provision for depreciation 7,810 2,655,103 1,537,747 (168,115 ) 4,032,545
27,492 2,704,278 2,163,226 (223,781 ) 4,671,215
Construction work in progress 10,792 881,899 165,389 - 1,058,080
38,284 3,586,177 2,328,615 (223,781 ) 5,729,295

OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts - - 1,263,338 - 1,263,338
Long-term notes receivable from associated companies - - 62,900 - 62,900
Investment in associated companies 2,598,022 - - (2,598,022 ) -
Other 2,529 21,657 202 - 24,388
2,600,551 21,657 1,326,440 (2,598,022 ) 1,350,626

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes 10,518 495,131 - (248,666 ) 256,983
Lease assignment receivable from associated companies - 67,256 - - 67,256
Goodwill 24,248 - - 24,248
Property taxes - 25,007 22,767 - 47,774
Pension assets 3,214 12,856 - - 16,070
Unamortized sale and leaseback costs - 38,120 - 47,575 85,695
Other 18,177 49,393 5,188 (37,939 ) 34,819
56,157 687,763 27,955 (239,030 ) 532,845
$ 3,885,657 $ 4,818,405 $ 4,057,876 $ (3,356,344 ) $ 9,405,594

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt $ - $ 738,087 $ 887,265 $ (16,896 ) $ 1,608,456
Notes payable-
Associated companies - 885,760 260,199 - 1,145,959
Other 700,000 - - - 700,000
Accounts payable-
Associated companies 554,844 1,419 119,773 (270,368 ) 405,668
Other 55,614 130,090 - - 185,704
Accrued taxes 3,378 116,383 47,292 (24,219 ) 142,834
Other 85,100 107,791 9,731 45,484 248,106
1,398,936 1,979,530 1,324,260 (265,999 ) 4,436,727

CAPITALIZATION:
Common stockholder's equity 2,460,215 1,011,907 1,579,614 (2,591,521 ) 2,460,215
Long-term debt and other long-term obligations - 1,320,773 62,900 (1,305,717 ) 77,956
2,460,215 2,332,680 1,642,514 (3,897,238 ) 2,538,171

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction - - - 1,051,871 1,051,871
Accumulated deferred income taxes - - 244,978 (244,978 ) -
Accumulated deferred investment tax credits - 35,350 24,619 - 59,969
Asset retirement obligations - 24,947 798,739 - 823,686
Retirement benefits 9,332 56,016 - - 65,348
Property taxes - 25,329 22,766 - 48,095
Lease market valuation liability - 341,881 - - 341,881
Other 17,174 22,672 - - 39,846
26,506 506,195 1,091,102 806,893 2,430,696
$ 3,885,657 $ 4,818,405 $ 4,057,876 $ (3,356,344 ) $ 9,405,594
120

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

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

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

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

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

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

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

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

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction - - - 1,060,119 1,060,119
Accumulated deferred income taxes - - 259,147 (259,147 ) -
Accumulated deferred investment tax credits - 36,054 25,062 - 61,116
Asset retirement obligations - 24,346 785,768 - 810,114
Retirement benefits 8,721 54,415 - - 63,136
Property taxes - 25,328 22,767 - 48,095
Lease market valuation liability - 353,210 - - 353,210
Other 19,800 21,829 - - 41,629
28,521 515,182 1,092,744 800,972 2,437,419
TOTAL LIABILITIES AND CAPITALIZATION $ 3,162,511 $ 4,452,888 $ 4,092,883 $ (3,286,018 ) $ 8,422,264

121

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Three Months Ended March 31, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)

NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES $ 273,827 $ (122,171 ) $ 8,108 $ 188 $ 159,952

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net 400,000 646,975 234,921 - 1,281,896
Redemptions and Repayments-
Long-term debt - (135,063 ) (153,540 ) - (288,603 )
Common stock dividend payments (10,000 ) - - - (10,000 )
     Net cash provided from financing activities 390,000 511,912 81,381 - 983,293

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (19,406 ) (375,391 ) (81,545 ) (187 ) (476,529 )
Proceeds from asset sales - 5,088 - - 5,088
Sales of investment securities held in trusts - - 173,123 - 173,123
Purchases of investment securities held in trusts - - (181,079 ) - (181,079 )
Loans to associated companies, net (644,604 ) - - - (644,604 )
Other 183 (19,438 ) 12 (1 ) (19,244 )
   Net cash used for investing activities (663,827 ) (389,741 ) (89,489 ) (188 ) (1,143,245 )

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

122

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Three Months Ended March 31, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)

NET CASH PROVIDED FROM
OPERATING ACTIVITIES $ 65,870 $ 55,003 $ 177,456 $ - $ 298,329

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Equity contribution from parent 700,000 700,000 - (700,000 ) 700,000
Short-term borrowings, net 250,000 - - (52,269 ) 197,731
Redemptions and Repayments-
Long-term debt - (616,728 ) (128,716 ) - (745,444 )
Short-term borrowings, net - (52,269 ) - 52,269 -
      Net cash provided from (used for) financing activities 950,000 31,003 (128,716 ) (700,000 ) 152,287

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (214 ) (81,400 ) (35,892 ) - (117,506 )
Sales of investment securities held in trusts - - 178,632 - 178,632
Purchases of investment securities held in trusts - - (188,076 ) - (188,076 )
Loans to associated companies, net (316,003 ) - (3,895 ) - (319,898 )
Investment in subsidiary (700,000 ) - - 700,000 -
Other 347 (4,606 ) 491 - (3,768 )
   Net cash used for investing activities (1,015,870 ) (86,006 ) (48,740 ) 700,000 (450,616 )

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

123

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Information” in Item 2 above.

ITEM 4. CONTROLS AND PROCEDURES

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY

~~The applicable registrant's~~FirstEnergy’s chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that the ~~applicable~~ registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to the registrant and its consolidated subsidiaries by others within those entities.

(b) CHANGES IN INTERNAL CONTROLS

During the quarter ended ~~September 30, 2007,~~March 31, 2008, there were no changes in FirstEnergy’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’s internal control over financial reporting.

ITEM 4T. CONTROLS AND PROCEDURES – FES, OE, CEI, TE, JCP&L, MET-ED AND PENELEC

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Each registrant's chief executive officer and chief financial officer have reviewed and evaluated such registrant's disclosure controls and procedures. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that such registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to such registrant and its consolidated subsidiaries by others within those entities.

(b) CHANGES IN INTERNAL CONTROLS

During the quarter ended March 31, 2008, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.

~~138~~124

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 10 and 11 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

See Item 1A RISK FACTORS in Part I of the Form 10-K for the year ended December 31, ~~2006~~2007 for a discussion of the risk factors of FirstEnergy and the subsidiary registrants. For the quarter ended ~~September 30, 2007,~~March 31, 2008, there have been no material changes to these risk factors.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

(c) FirstEnergy

The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock.

	Period								Period
	July 1-31,		August 1-31,		September 1-30,		Third		January 1-31,	February 1-29,	March 1-31,	First
	2007		2007		2007		Quarter		2008	2008	2008	Quarter
Total Number of Shares Purchased ^(a)	29,656		83,448		253,701		366,805		329,106	16,853	988,386	1,334,345
Average Price Paid per Share	$66.00		$62.95		$61.85		$62.44		$76.56	$71.68	$68.55	$70.57
Total Number of Shares Purchased
As Part of Publicly Announced Plans
or Programs ^(b)		-		-		-		-	-	-	-	-
Maximum Number (or Approximate Dollar
Value) of Shares that May Yet Be
Purchased Under the Plans or Programs		1,629,890		1,629,890		1,629,890		1,629,890	-	-	-	-

^(a)	Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its ~~Executive and Director~~2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive ~~and Director Incentive~~Deferred Compensation Plan, and shares purchased as part of publicly announced plans.

^(b)	~~FirstEnergy publicly announced, on January 30,~~On December 10, 2007, aFirstEnergy’s plan to repurchase up to 16 million shares of its common stock through June 30, 2008. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock under this plan through an accelerated share repurchase program with an affiliate of Morgan Stanley and Co., Incorporated at an initial price of $62.63 per share.2008, was concluded.

~~139~~125

ITEM 6. EXHIBITS

Exhibit Number


FirstEnergy
	~~10.1~~		Amendment to Agreement for Engineering, Procurement and Construction of Air Quality Control Systems by and between FirstEnergy Generation Corp. and Bechtel Power Corporation dated September 14, 2007 (Form 8-K dated September 18, 2007)*
	~~10.2~~		~~FirstEnergy Corp. Executive Deferred Compensation Plan as amended September 18, 2007~~ ~~(Form 8-K dated September 21, 2007)~~
	~~10.3~~		~~FirstEnergy Corp. Supplemental Executive Retirement Plan as amended September 18, 2007~~ ~~(Form 8-K dated September 21, 2007)~~
	12		Fixed charge ratios
	15		Letter from independent registered public accounting firm
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
FES
		12	~~Fixed charge ratios~~
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
OE
		12	Fixed charge ratios
		15	Letter from independent registered public accounting firm
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
CEI
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
TE
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
JCP&L
		12	~~Fixed charge ratios~~
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
Met-Ed
		12	~~Fixed charge ratios~~
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
Penelec
		~~4.1~~	~~Form of Pennsylvania Electric Company 6.05% Senior Notes due 2017 (incorporated by reference to a Form 8-K dated August 31, 2007)~~
		~~10.1~~	Registration Rights Agreement, dated as of August 30, 2007, among Pennsylvania Electric Company and Citigroup Global Markets Inc., Lehman Brothers Inc. and Scotia Capital (USA) Inc., as representatives of the several initial purchasers named in the Purchase Agreement (incorporated by reference to a Form 8-K dated August 31, 2007)
		12	Fixed charge ratios
		15	Letter from independent registered public accounting firm
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

* Confidential treatment has been requested for certain portions of the Exhibit. Omitted portions have been filed separately with the SEC.

Pursuant to reporting requirements of respective financings, FirstEnergy, ~~FES,~~ OE ~~JCP&L, Met-Ed~~ and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.

~~140~~126

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

~~October 31, 2007~~May 8, 2008

	FIRSTENERGY CORP.
	Registrant

	FIRSTENERGY SOLUTIONS CORP.
	Registrant

	OHIO EDISON COMPANY
	Registrant

	THE CLEVELAND ELECTRIC
	ILLUMINATING COMPANY
	Registrant

	THE TOLEDO EDISON COMPANY
	Registrant

	METROPOLITAN EDISON COMPANY
	Registrant

	PENNSYLVANIA ELECTRIC COMPANY
	Registrant

	/s/ Harvey L. Wagner
	Harvey L. Wagner
	Vice President, Controller
	and Chief Accounting Officer

	JERSEY CENTRAL POWER & LIGHT COMPANY
	Registrant



	/s/ Paulette R. Chatman
	Paulette R. Chatman
	Controller
	(Principal Accounting Officer)

~~141~~127

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
	~~76 South Main Street~~
	~~Akron, OH 44308~~
	Telephone (800)736-3402

333-145140-01	FIRSTENERGY SOLUTIONS CORP.	31-1560186
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	~~c/o FirstEnergy Corp.~~
	~~76 South Main Street~~
	~~Akron, OH 44308~~
	Telephone (800)~~736-3402~~736-3402

~~1-2578~~ 1-2323	~~OHIO EDISON~~THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	~~34-0437786~~ 34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	~~c/o FirstEnergy Corp.~~
	~~76 South Main Street~~
	~~Akron, OH 44308~~
	Telephone (800)736-3402

~~1-2323~~ 1-3583	THE ~~CLEVELAND ELECTRIC ILLUMINATING~~TOLEDO EDISON COMPANY	~~34-0150020~~ 34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	~~c/o FirstEnergy Corp.~~
	~~76 South Main Street~~
	~~Akron, OH 44308~~
	Telephone (800)736-3402

~~1-3583~~ 1-3141	~~THE TOLEDO EDISON~~JERSEY CENTRAL POWER & LIGHT COMPANY	~~34-4375005~~ 21-0485010
	(~~An Ohio~~A New Jersey Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	~~c/o FirstEnergy Corp.~~
	~~76 South Main Street~~
	~~Akron, OH 44308~~
	Telephone (800)736-3402

~~1-3141~~ 1-446	~~JERSEY CENTRAL POWER & LIGHT~~METROPOLITAN EDISON COMPANY	~~21-0485010~~ 23-0870160
	(A ~~New Jersey~~Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	~~c/o FirstEnergy Corp.~~
	~~76 South Main Street~~
	~~Akron, OH 44308~~
	Telephone (800)736-3402

~~1-446~~ 1-3522	~~METROPOLITAN EDISON~~PENNSYLVANIA ELECTRIC COMPANY	~~23-0870160~~ 25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	~~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~~

Yes (X) No ( )	FirstEnergy Corp., ~~FirstEnergy Solutions Corp.,~~ Ohio Edison ~~Company, The Cleveland Electric Illuminating~~ Company and Pennsylvania Electric Company
Yes ( ) No (X)	FirstEnergy Solutions Corp., The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company and Metropolitan Edison Company

Large Accelerated Filer (X)	FirstEnergy Corp.
Accelerated Filer ( )	N/A
Non-accelerated Filer ~~(X)~~(Do not check if a smaller reporting company) (X)	FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company

	OUTSTANDING
CLASS	AS OF ~~OCTOBER 31, 2007~~MAY 8, 2008
FirstEnergy Corp., ~~$.10~~$0.10 par value	304,835,407
FirstEnergy Solutions Corp., no par value	7
Ohio Edison Company, no par value	60
The Cleveland Electric Illuminating Company, no par value	67,930,743
The Toledo Edison Company, $5 par value	29,402,054
Jersey Central Power & Light Company, $10 par value	14,421,637
Metropolitan Edison Company, no par value	859,500
Pennsylvania Electric Company, $20 par value	4,427,577

		Pages
Glossary of Terms		~~iii-iv~~iii-v

Part I. Financial Information

Items 1. and 2. - Financial Statements and Management’s Discussion and Analysis ~~of Financial~~ofFinancial Condition and Results of Operations.

		~~Notes to Consolidated Financial Statements~~	~~1-34~~

FirstEnergy Corp.

	~~Consolidated Statements of Income~~	35
	~~Consolidated Statements of Comprehensive Income~~	36
	~~Consolidated Balance Sheets~~	37
	~~Consolidated Statements of Cash Flows~~	38
	~~Report of Independent Registered Public Accounting Firm~~	39
	Management's Discussion and Analysis of Financial Condition and	~~40-80~~1-32
	Results of Operations
	Report of Independent Registered Public Accounting Firm	33
	Consolidated Statements of Income	34
	Consolidated Statements of Comprehensive Income	35
	Consolidated Balance Sheets	36
	Consolidated Statements of Cash Flows	37

FirstEnergy Solutions Corp.

	~~Consolidated Statements~~Management's Narrative Analysis of ~~Income and Comprehensive Income~~Results of Operations	81
	~~Consolidated Balance Sheets~~	82
	~~Consolidated Statements of Cash Flows~~	8338-40
	Report of Independent Registered Public Accounting Firm	8441
	~~Management's Narrative Analysis~~Consolidated Statements of ~~Results~~Income and Comprehensive Income	42
	Consolidated Balance Sheets	43
	Consolidated Statements of ~~Operations~~Cash Flows	~~85-87~~44

Ohio Edison Company

	~~Consolidated Statements~~Management's Narrative Analysis of ~~Income and Comprehensive Income~~Results of Operations	88
	~~Consolidated Balance Sheets~~	89
	~~Consolidated Statements of Cash Flows~~	9045-46
	Report of Independent Registered Public Accounting Firm	9147
	~~Management's Narrative Analysis~~Consolidated Statements of ~~Results~~Income and Comprehensive Income	48
	Consolidated Balance Sheets	49
	Consolidated Statements of ~~Operations~~Cash Flows	~~92-93~~50

The Cleveland Electric Illuminating Company

	~~Consolidated Statements~~Management's Narrative Analysis of ~~Income and Comprehensive Income~~Results of Operations	94
	~~Consolidated Balance Sheets~~	95
	~~Consolidated Statements of Cash Flows~~	9651-52
	Report of Independent Registered Public Accounting Firm	9753
	~~Management's Narrative Analysis~~Consolidated Statements of ~~Results~~Income and Comprehensive Income	54
	Consolidated Balance Sheets	55
	Consolidated Statements of ~~Operations~~Cash Flows	~~98-99~~56

The Toledo Edison Company

	~~Consolidated Statements~~Management's Narrative Analysis of ~~Income and Comprehensive Income~~Results of Operations	~~100~~
	~~Consolidated Balance Sheets~~	~~101~~
	~~Consolidated Statements of Cash Flows~~	~~102~~57-58
	Report of Independent Registered Public Accounting Firm	~~103~~59
	Consolidated Statements of Income and Comprehensive Income	60
	Consolidated Balance Sheets	61
	Consolidated Statements of Cash Flows	62

Jersey Central Power & Light Company		Pages

	Management's Narrative Analysis of Results of Operations	~~104-105~~63-64
	Report of Independent Registered Public Accounting Firm

~~Jersey Central Power & Light Company~~		~~Pages~~
		65
	Consolidated Statements of Income and Comprehensive Income	~~106~~66
	Consolidated Balance Sheets	~~107~~67
	Consolidated Statements of Cash Flows	~~108~~
	~~Report of Independent Registered Public Accounting Firm~~	~~109~~
	~~Management's Narrative Analysis of Results of Operations~~	~~110-111~~68

Metropolitan Edison Company

	~~Consolidated Statements~~Management's Narrative Analysis of ~~Income and Comprehensive Income~~Results of Operations	~~112~~
	~~Consolidated Balance Sheets~~	~~113~~
	~~Consolidated Statements of Cash Flows~~	~~114~~69-70
	Report of Independent Registered Public Accounting Firm	~~115~~71
	~~Management's Narrative Analysis~~Consolidated Statements of ~~Results~~Income and Comprehensive Income	72
	Consolidated Balance Sheets	73
	Consolidated Statements of ~~Operations~~Cash Flows	~~116-117~~74

Pennsylvania Electric Company

	~~Consolidated Statements~~Management's Narrative Analysis of ~~Income and Comprehensive Income~~Results of Operations	~~118~~
	~~Consolidated Balance Sheets~~	~~119~~
	~~Consolidated Statements of Cash Flows~~	~~120~~75-76
	Report of Independent Registered Public Accounting Firm	~~121~~77
	~~Management's Narrative Analysis~~Consolidated Statements of ~~Results~~Income and Comprehensive Income	78
	Consolidated Balance Sheets	79
	Consolidated Statements of ~~Operations~~Cash Flows	~~122-123~~80

Combined Management’s Discussion and Analysis of Registrant Subsidiaries		~~124-137~~81-94

Combined Notes to Consolidated Financial Statements		95-123

Item 3. Quantitative and Qualitative Disclosures About Market Risk.		~~138~~124

Item 4. Controls and ~~Procedures.~~Procedures – FirstEnergy.		~~138~~124

Item 4T. Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.		124

Part II. Other Information

Item 1. Legal Proceedings.		~~139~~125

Item 1A. Risk Factors.		~~139~~125

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.		~~139~~125

Item 6. Exhibits.		~~140~~126

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
Companies	OE, CEI, TE, JCP&L, Met-Ed and Penelec
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial and other corporate support services
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., a public utility holding company
~~FSG~~	~~FirstEnergy Facilities Services Group, LLC, former parent company of several heating, ventilation,~~ ~~air conditioning and energy management companies~~
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition Funding	JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds
JCP&L Transition Funding II	JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition bonds
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
~~MYR~~	~~MYR Group, Inc., a utility infrastructure construction service company~~
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies	Met-Ed, Penelec and Penn
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
TEBSA	~~Termobarranquilla~~Termobarranquila S.A., Empresa de Servicios Publicos

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

~~ALJ~~AEP	~~Administrative Law Judge~~
~~APIC~~	~~Additional Paid-In Capital~~American Electric Power Company, Inc.
AOCL	Accumulated Other Comprehensive Loss
AQC	Air Quality Control
ARB	Accounting Research Bulletin
ARO	Asset Retirement Obligation
ASM	Ancillary Services Market
BGS	Basic Generation Service
BPJ	Best Professional Judgment
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
~~CAL~~	~~Confirmatory Action Letter~~
CAMR	Clean Air Mercury Rule
CBP	Competitive Bid Process
CO₂	Carbon Dioxide
DFI	Demand for Information
DOJ	United States Department of Justice
DRA	Division of Ratepayer Advocate
~~ECAR~~	~~East Central Area Reliability Coordination Agreement~~
EIS	Energy Independence Strategy
EITF	Emerging Issues Task Force
~~EITF 06-11~~	~~EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends or Share-Based~~ ~~Payment Awards”~~
EMP	Energy Master Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
~~ERO~~ESP	Electric ~~Reliability Organization~~Security Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
~~FIN 39-1~~	~~FIN 39-1, “Amendment of FASB Interpretation No. 39”~~
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"

FIN 48	FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109”
FirstCom	First Communications, Inc.

FMB	First Mortgage Bonds
FSP	FASB Staff Position
FSP FAS 157-2	FSP FAS 157-2, “Effective Date of FASB Statement No. 157”
FTR	Financial Transmission Rights
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
ICE	Intercontinental Exchange
IRS	Internal Revenue Service
ISO	Independent System Operator
kV	Kilovolt
KWH	Kilowatt-hours
LIBOR	London Interbank Offered Rate
LOC	Letter of Credit
MEIUG	Met-Ed Industrial Users Group
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
~~MOU~~MRO	~~Memorandum of Understanding~~Market Rate Offer
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
NOPR	Notice of Proposed Rulemaking
NOV	Notice of Violation
NO_X	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
NYMEX	New York Mercantile Exchange
OCA	Office of Consumer Advocate
~~OCC~~OTC	~~Office of~~Over the ~~Ohio Consumers’ Counsel~~Counter
OVEC	Ohio Valley Electric Corporation
PCRB	Pollution Control Revenue Bond
PICA	Penelec Industrial Customer Alliance
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PSA	Power Supply Agreement
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RECB	Regional Expansion Criteria and Benefits
RFP	Request for Proposal
RPM	Reliability Pricing Model
RSP	Rate Stabilization Plan
RTO	Regional Transmission Organization
~~RTOR~~	~~Regional Through and Out Rates~~
S&P	Standard & Poor’s Ratings Service
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
SFAS	Statement of Financial Accounting Standards
SFAS ~~107~~	~~SFAS No. 107, “Disclosure about Fair Value of Financial Instruments”~~
~~SFAS~~ 109	SFAS No. 109, “Accounting for Income Taxes”
SFAS 123(R)	SFAS No. 123(R), "Share-Based Payment"
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS ~~142~~141(R)	SFAS ~~No. 142, “Goodwill and Other Intangible Assets”~~No 141(R), “Business Combinations”
SFAS 143	SFAS No. 143, “Accounting for Asset Retirement Obligations”
SFAS 157	SFAS No. 157, “Fair Value Measurements”
SFAS 159	SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”
SFAS 160	SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”
SFAS 161	SFAS No 161, “Disclosure about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”

SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO₂	Sulfur Dioxide
~~SRM~~	~~Special Reliability Master~~
TBC	Transition Bond Charge
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
TSC	Transmission Service Charge
VIE	Variable Interest Entity

Change in Basic Earnings Per Share From Prior Year First Quarter

Basic Earnings Per Share – First Quarter 2007	$ 0.92
Gain on non-core asset sales – 2008	0.06
Saxton decommissioning regulatory asset – 2007	(0.05)
Trust securities impairment	(0.02)
Revenues	0.55
Fuel and purchased power	(0.42)
Depreciation and amortization	(0.03)
Deferral of new regulatory assets	(0.03)
Energy Delivery O&M expenses	(0.03)
General taxes	(0.02)
Corporate-owned life insurance	(0.06)
Other expenses	0.01
Reduced common shares outstanding	0.03
Basic Earnings Per Share – First Quarter 2008	$ 0.91

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Reconciliation of Basic and Diluted Earnings per Share	2007		2006		2007		2006
	*(In millions, except per share amounts)*

Income from continuing operations	$	413	$	452	$	1,041	$	983
Discontinued operations		-		2		-		(4	)
Redemption premium on subsidiary preferred stock		-		-		-		(3	)
Net earnings available for common shareholders	$	413	$	454	$	1,041	$	976

Average shares of common stock outstanding – Basic		304		322		307		326
Assumed exercise of dilutive stock options and awards		3		3		4		3
Average shares of common stock outstanding – Dilutive		307		325		311		329

Earnings per share:
Basic earnings per share:
Earnings from continuing operations	$	1.36	$	1.40	$	3.39	$	3.00
Discontinued operations		-		0.01		-		(0.01	)
Net earnings per basic share	$	1.36	$	1.41	$	3.39	$	2.99

Diluted earnings per share:
Earnings from continuing operations	$	1.34	$	1.39	$	3.35	$	2.98
Discontinued operations		-		0.01		-		(0.01	)
Net earnings per diluted share	$	1.34	$	1.40	$	3.35	$	2.97

	Three Months			Nine Months
	(In millions)

FSG subsidiaries	$	2	$	(6	)
MYR		-		2
Total	$	2	$	(4	)

			Borrowing
Subsidiary Company	Parent Company		Capacity
			*(In millions)*
OES Capital, Incorporated		OE	$	170
Centerior Funding Corp.		CEI		200
Penn Power Funding LLC		Penn		25
Met-Ed Funding LLC		Met-Ed		80
Penelec Funding LLC		Penelec		75
			$	550

Segment Financial Information
					Ohio
	Energy		Competitive		Transitional
	Delivery		Energy		Generation						Reconciling
Three Months Ended	Services		Services		Services			Other			Adjustments			Consolidated
	(In millions)
September 30, 2007
External revenues	$	2,520	$	370	$	723		$	9		$	19		$	3,641
Internal revenues		-		806		-			-			(806	)		-
Total revenues		2,520		1,176		723			9			(787	)		3,641
Depreciation and amortization		299		51		(16	)		1			8			343
Investment income		58		5		-			1			(34	)		30
Net interest charges		117		39		-			1			37			194
Income taxes		175		99		11			(2	)		(10	)		273
Net income		269		148		16			6			(26	)		413
Total assets		23,308		7,182		268			232			663			31,653
Total goodwill		5,585		24		-			-			-			5,609
Property additions		209		199		-			1			21			430

September 30, 2006
External revenues	$	2,306	$	353	$	690		$	24		$	(9	)	$	3,364
Internal revenues		-		762		-			-			(762	)		-
Total revenues		2,306		1,115		690			24			(771	)		3,364
Depreciation and amortization		227		49		(40	)		1			6			243
Investment income		80		18		-			-			(52	)		46
Net interest charges		107		49		-			2			22			180
Income taxes		187		112		18			(14	)		(30	)		273
Income from
continuing operations		280		169		27			25			(49	)		452
Discontinued operations		-		-		-			2			-			2
Net income		280		169		27			27			(49	)		454
Total assets		23,940		6,822		240			321			839			32,162
Total goodwill		5,911		24		-			-			-			5,935
Property additions		119		126		-			-			6			251

Nine Months Ended

September 30, 2007
External revenues	$	6,655	$	1,089	$	1,968		$	29		$	(18	)	$	9,723
Internal revenues		-		2,210		-			-			(2,210	)		-
Total revenues		6,655		3,299		1,968			29			(2,228	)		9,723
Depreciation and amortization		767		153		(80	)		3			20			863
Investment income		190		13		1			1			(112	)		93
Net interest charges		340		131		1			3			97			572
Income taxes		464		259		46			-			(74	)		695
Net income		695		388		69			13			(124	)		1,041
Total assets		23,308		7,182		268			232			663			31,653
Total goodwill		5,585		24		-			-			-			5,609
Property additions		609		462		-			4			52			1,127

September 30, 2006
External revenues	$	5,876	$	1,077	$	1,808		$	92		$	(32	)	$	8,821
Internal revenues		14		1,997		-			-			(2,011	)		-
Total revenues		5,890		3,074		1,808			92			(2,043	)		8,821
Depreciation and amortization		657		143		(89	)		3			17			731
Investment income		244		35		-			1			(160	)		120
Net interest charges		308		139		1			5			60			513
Income taxes		468		201		58			(17	)		(85	)		625
Income from
continuing operations		702		302		88			30			(139	)		983
Discontinued operations		-		-		-			(4	)		-			(4	)
Net income		702		302		88			26			(139	)		979
Total assets		23,940		6,822		240			321			839			32,162
Total goodwill		5,911		24		-			-			-			5,935
Property additions		489		473		-			-			28			990

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended September 30, 2007	FES			FGCO			NGC			Eliminations			Consolidated
	*(In thousands)*

REVENUES	$	1,180,449		$	496,204		$	280,072		$	(785,817	)	$	1,170,908

EXPENSES:
Fuel		10,944			261,759			29,083			-			301,786
Purchased power from non-affiliates		228,755			-			-			-			228,755
Purchased power from affiliates		774,873			57,927			15,525			(785,817	)		62,508
Other operating expenses		41,828			75,985			117,220			-			235,033
Provision for depreciation		650			24,669			23,181			-			48,500
General taxes		5,406			11,788			5,048			-			22,242
Total expenses		1,062,456			432,128			190,057			(785,817	)		898,824

OPERATING INCOME		117,993			64,076			90,015			-			272,084

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		82,870			2,375			3,935			(76,525	)		12,655
Interest expense to affiliates		(676	)		(4,769	)		(4,196	)		-			(9,641	)
Interest expense - other		(808	)		(21,274	)		(9,712	)		-			(31,794	)
Capitalized interest		9			3,889			1,233			-			5,131
Total other income (expense)		81,395			(19,779	)		(8,740	)		(76,525	)		(23,649	)

INCOME BEFORE INCOME TAXES		199,388			44,297			81,275			(76,525	)		248,435

INCOME TAXES		44,624			19,850			29,197			-			93,671

NET INCOME	$	154,764		$	24,447		$	52,078		$	(76,525	)	$	154,764

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of September 30, 2007	FES		FGCO		NGC		Eliminations			Consolidated
	*(In thousands)*
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	2	$	-	$	-	$	-		$	2
Receivables-
Customers		144,443		-		-		-			144,443
Associated companies		282,118		169,108		113,936		(279,700	)		285,462
Other		4,862		554		-		-			5,416
Notes receivable from associated companies		-		242,612		-		-			242,612
Materials and supplies, at average cost		195		224,149		216,722		-			441,066
Prepayments and other		67,892		13,693		2,240		-			83,825
		499,512		650,116		332,898		(279,700	)		1,202,826

PROPERTY, PLANT AND EQUIPMENT:
In service		25,171		5,023,255		3,530,969		(395,817	)		8,183,578
Less - Accumulated provision for depreciation		6,807		2,539,192		1,476,051		(169,154	)		3,852,896
		18,364		2,484,063		2,054,918		(226,663	)		4,330,682
Construction work in progress		1,034		414,243		181,602		-			596,879
		19,398		2,898,306		2,236,520		(226,663	)		4,927,561

INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,342,083		-			1,342,083
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		2,462,960		-		-		(2,462,960	)		-
Other		5,315		34,447		202		-			39,964
		2,468,275		34,447		1,405,185		(2,462,960	)		1,444,947

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		28,756		403,890		-		(192,464	)		240,182
Goodwill		24,248		-		-		-			24,248
Property taxes		-		20,946		23,165		-			44,111
Pension assets		1,154		8,295		-		-			9,449
Other		33,049		32,477		5,112		-			70,638
		87,207		465,608		28,277		(192,464	)		388,628
	$	3,074,392	$	4,048,477	$	4,002,880	$	(3,161,787	)	$	7,963,962

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	-	$	624,517	$	861,265	$	(16,061	)	$	1,469,721
Notes payable-
Associated companies		223,942		-		13,128		-			237,070
Other		-		-		-		-			-
Accounts payable-
Associated companies		279,976		158,500		273,919		(279,700	)		432,695
Other		65,782		112,038		-		-			177,820
Accrued taxes		44,995		461,635		30,430		-			537,060
Other		60,252		59,770		9,731		33,486			163,239
		674,947		1,416,460		1,188,473		(262,275	)		3,017,605

CAPITALIZATION:
Common stockholder's equity		2,369,019		905,100		1,557,860		(2,462,960	)		2,369,019
Long-term debt		-		1,575,653		242,400		(1,312,857	)		505,196
		2,369,019		2,480,753		1,800,260		(3,775,817	)		2,874,215

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,068,769			1,068,769
Accumulated deferred income taxes		-		-		192,464		(192,464	)		-
Accumulated deferred investment tax credits		-		36,764		25,511		-			62,275
Asset retirement obligations		-		24,350		773,007		-			797,357
Retirement benefits		7,843		45,662		-		-			53,505
Property taxes		-		21,268		23,165		-			44,433
Other		22,583		23,220		-		-			45,803
		30,426		151,264		1,014,147		876,305			2,072,142
	$	3,074,392	$	4,048,477	$	4,002,880	$	(3,161,787	)	$	7,963,962

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Nine Months Ended September 30, 2007	FES			FGCO			NGC			Eliminations			Consolidated
	*(In thousands)*

NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES	$	(17,080	)	$	350,927		$	146,468		$	-		$	480,315

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			1,328,919			-			(1,328,919	)		-
Equity contribution from parent		710,468			700,000			1,325			(701,325	)		710,468
Short-term borrowings, net		223,942			-			13,128			(237,070	)		-
Redemptions and Repayments-
Long-term debt		-			(795,019	)		(315,155	)		-			(1,110,174	)
Short-term borrowings, net		-			(1,022,197	)		-			237,070			(785,127	)
Common stock		(600,000	)		-			-			-			(600,000	)
Common stock dividend payments		(67,000	)		-			-			-			(67,000	)
Net cash provided from (used for) financing activities		267,410			211,703			(300,702	)		(2,030,244	)		(1,851,833	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(10,119	)		(332,499	)		(140,289	)		-			(482,907	)
Proceeds from asset sales		-			12,990			-			-			12,990
Proceeds from sale and leaseback transaction		-			-			-			1,328,919			1,328,919
Sales of investment securities held in trusts		-			-			521,535			-			521,535
Purchases of investment securities held in trusts		-			-			(521,535	)		-			(521,535	)
Loan repayments from (loans to) associated companies, net		460,023			(242,612	)		292,896			-			510,307
Investment in subsidiary		(701,325	)		-			-			701,325			-
Other		1,091			(509	)		1,627			-			2,209
Net cash provided from (used for) investing activities		(250,330	)		(562,630	)		154,234			2,030,244			1,371,518

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

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	*(In millions, except per share amounts)*
REVENUES:
Electric utilities	$	3,260		$	2,996		$	8,685		$	7,677
Unregulated businesses		381			368			1,038			1,144
Total revenues *		3,641			3,364			9,723			8,821

EXPENSES:
Fuel and purchased power		1,495			1,317			3,801			3,306
Other operating expenses		756			758			2,255			2,230
Provision for depreciation		162			153			477			445
Amortization of regulatory assets		288			243			785			665
Deferral of new regulatory assets		(107	)		(153	)		(399	)		(379	)
General taxes		197			187			589			553
Total expenses		2,791			2,505			7,508			6,820

OPERATING INCOME		850			859			2,215			2,001

OTHER INCOME (EXPENSE):
Investment income		30			46			93			120
Interest expense		(203	)		(185	)		(593	)		(528	)
Capitalized interest		9			7			21			21
Subsidiaries’ preferred stock dividends		-			(2	)		-			(6	)
Total other expense		(164	)		(134	)		(479	)		(393	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		686			725			1,736			1,608

INCOME TAXES		273			273			695			625

INCOME FROM CONTINUING OPERATIONS		413			452			1,041			983

Discontinued operations (net of income tax benefits of
$1 million and $2 million in the three months and
nine months ended September 30, 2006, respectively) (Note 4)		-			2			-			(4	)

NET INCOME	$	413		$	454		$	1,041		$	979

BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income from continuing operations	$	1.36		$	1.40		$	3.39		$	3.00
Discontinued operations		-			0.01			-			(0.01	)
Net earnings per basic share	$	1.36		$	1.41		$	3.39		$	2.99


WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		304			322			307			326

DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income from continuing operations	$	1.34		$	1.39		$	3.35		$	2.98
Discontinued operations		-			0.01			-			(0.01	)
Net earnings per diluted share	$	1.34		$	1.40		$	3.35		$	2.97


WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		307			325			311			329

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	1.00		$	0.45		$	1.50		$	1.35


* Includes excise tax collections of $108 million in the third quarter of both 2007 and 2006, and $308 million and $297 million in the nine
months ended September 2007 and 2006, respectively.

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	*(In millions)*

NET INCOME	$	413		$	454		$	1,041		$	979

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(12	)		-			(34	)		-
Unrealized gain (loss) on derivative hedges		(10	)		(28	)		10			45
Change in unrealized gain on available for sale securities		26			26			89			39
Other comprehensive income (loss)		4			(2	)		65			84
Income tax expense (benefit) related to other
comprehensive income		-			(1	)		19			30
Other comprehensive income (loss), net of tax		4			(1	)		46			54

COMPREHENSIVE INCOME	$	417		$	453		$	1,087		$	1,033


The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2007			2006
	*(In millions)*
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	30		$	90
Receivables-
Customers (less accumulated provisions of $38 million and
$43 million, respectively, for uncollectible accounts)		1,432			1,135
Other (less accumulated provisions of $22 million and
$24 million, respectively, for uncollectible accounts)		194			132
Materials and supplies, at average cost		543			577
Prepayments and other		207			149
		2,406			2,083
PROPERTY, PLANT AND EQUIPMENT:
In service		24,353			24,105
Less - Accumulated provision for depreciation		10,248			10,055
		14,105			14,050
Construction work in progress		933			617
		15,038			14,667
INVESTMENTS:
Nuclear plant decommissioning trusts		2,140			1,977
Investments in lease obligation bonds		738			811
Other		787			746
		3,665			3,534
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,609			5,898
Regulatory assets		4,047			4,441
Pension assets		318			-
Other		570			573
		10,544			10,912
	$	31,653		$	31,196
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	2,265		$	1,867
Short-term borrowings		573			1,108
Accounts payable		760			726
Accrued taxes		671			598
Accrued interest		215			111
Other		894			845
		5,378			5,255
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $.10 par value, authorized 375,000,000 shares-
304,835,407 and 319,205,517 shares outstanding, respectively		30			32
Other paid-in capital		5,564			6,466
Accumulated other comprehensive loss		(213	)		(259	)
Retained earnings		3,387			2,806
Unallocated employee stock ownership plan common stock-
521,818 shares		-			(10	)
Total common stockholders' equity		8,768			9,035
Long-term debt and other long-term obligations		8,617			8,535
		17,385			17,570
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,317			2,740
Asset retirement obligations		1,247			1,190
Deferred gain on sale and leaseback transaction		1,069			-
Power purchase contract loss liability		872			1,182
Retirement benefits		918			944
Lease market valuation liability		684			767
Other		1,783			1,548
		8,890			8,371
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
	$	31,653		$	31,196

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
balance sheets.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months Ended
	September 30,
	2007			2006
	*(In millions)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,041		$	979
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		477			445
Amortization of regulatory assets		785			665
Deferral of new regulatory assets		(399	)		(379	)
Nuclear fuel and lease amortization		75			67
Deferred purchased power and other costs		(265	)		(323	)
Deferred income taxes and investment tax credits, net		(158	)		36
Investment impairment		16			13
Deferred rents and lease market valuation liability		(41	)		(54	)
Accrued compensation and retirement benefits		(50	)		78
Commodity derivative transactions, net		5			28
Gain on asset sales		(35	)		(38	)
Income from discontinued operations		-			4
Cash collateral		(50	)		(98	)
Pension trust contribution		(300	)		-
Decrease (increase) in operating assets-
Receivables		(329	)		(7	)
Materials and supplies		62			(30	)
Prepayments and other current assets		(39	)		(49	)
Increase (decrease) in operating liabilities-
Accounts payable		(15	)		(93	)
Accrued taxes		355			(32	)
Accrued interest		104			104
Electric service prepayment programs		(52	)		(45	)
Other		(36	)		(28	)
Net cash provided from operating activities		1,151			1,243

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		1,100			1,235
Short-term borrowings, net		-			482
Redemptions and Repayments-
Common stock		(918	)		(600	)
Preferred stock		-			(107	)
Long-term debt		(647	)		(993	)
Short-term borrowings, net		(535	)		-
Net controlled disbursement activity		6			(22	)
Stock-based compensation tax benefit		16			-
Common stock dividend payments		(464	)		(439	)
Net cash used for financing activities		(1,442	)		(444	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(1,127	)		(990	)
Proceeds from asset sales		37			83
Proceeds from sale and leaseback transaction		1,329			-
Sales of investment securities held in trusts		1,010			1,370
Purchases of investment securities held in trusts		(1,067	)		(1,381	)
Cash investments		48			109
Other		1			(13	)
Net cash provided from (used for) investing activities		231			(822	)

Net decrease in cash and cash equivalents		(60	)		(23	)
Cash and cash equivalents at beginning of period		90			64
Cash and cash equivalents at end of period	$	30		$	41

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

Change in Basic Earnings Per Share From Prior Year Periods	Three Months Ended September 30,			Nine Months Ended September 30,

Basic Earnings Per Share – 2006	$	1.41		$	2.99
Revenues		0.55			1.76
Fuel and purchased power		(0.37	)		(0.99	)
Depreciation and amortization		(0.11	)		(0.29	)
Deferral of new regulatory assets		(0.09	)		(0.01	)
Other expenses		(0.16	)		(0.36	)
Reduced common shares outstanding		0.08			0.18
Non-core asset sales/impairments – 2006		(0.01	)		0.03
PPUC NUG Accounting Adjustment – 2006		0.02			0.02
Non-core asset sales -- 2007		0.04			0.04
Saxton decommissioning regulatory asset – 2007		-			0.05
Trust securities impairment – 2007		-			(0.03	)
Basic Earnings Per Share – 2007	$	1.36		$	3.39

		Three Months Ended September 30,									Nine Months Ended September 30,
								Increase									Increase
		2007			2006			(Decrease)			2007			2006			(Decrease)
		*(In millions, except per share amounts)*
Net Income (Loss)
By Business Segment:
Energy delivery services	$	269		$	280		$	(11	)	$	695		$	702		$	(7	)
Competitive energy services		148			169			(21	)		388			302			86
Ohio transitional generation services		16			27			(11	)		69			88			(19	)
Other and reconciling adjustments*		(20	)		(22	)		2			(111	)		(113	)		2
Total	$	413		$	454		$	(41	)	$	1,041		$	979		$	62

Basic Earnings Per Share:
Income from continuing operations	$	1.36		$	1.40		$	(0.04	)	$	3.39		$	3.00		$	0.39
Discontinued operations		-			0.01			(0.01	)		-			(0.01	)		0.01
Net earnings per basic share	$	1.36		$	1.41		$	(0.05	)	$	3.39		$	2.99		$	0.40

Diluted Earnings Per Share:
Income from continuing operations	$	1.34		$	1.39		$	(0.05	)	$	3.35		$	2.98		$	0.37
Discontinued operations		-			0.01			(0.01	)		-			(0.01	)		0.01
Net earnings per diluted share	$	1.34		$	1.40		$	(0.06	)	$	3.35		$	2.97		$	0.38

	Three Months Ended
	September 30,
Revenues by Type of Service	2007		2006		Increase (Decrease)
	*(In millions)*
Distribution services	$	1,104	$	1,124	$	(20	)
Generation sales:
Retail		942		857		85
Wholesale		207		91		116
Total generation sales		1,149		948		201
Transmission		219		177		42
Other		48		57		(9	)
Total Revenues	$	2,520	$	2,306	$	214

	Increase
Source of Change in Non-Affiliated Generation Sales	(Decrease)
	*(In millions)*
Retail:
Effect of 0.2% increase in sales volumes	$	1
Change in prices		10
		11
Wholesale:
Effect of 11% decrease in sales volumes		(15	)
Change in prices		30
		15
Net Increase in Non-Affiliated Generation Sales	$	26


Source of Change in Affiliated Generation Sales	Increase
	*(In millions)*
Ohio Companies:
Effect of 2% increase in sales volumes	$	12
Change in prices		14
		26
Pennsylvania Companies:
Effect of 8% increase in sales volumes		13
Change in prices		5
		18
Net Increase in Affiliated Generation Sales	$	44

Source of Change in Purchased Power	Increase
	*(In millions)*

Change due to increased unit costs	$	14
Change due to 18% increase in volume		31
Change due to new PJM capacity market		10
Total Increase in Purchased Power Costs	$	55

	Nine Months Ended
	September 30,
Operating Cash Flows	2007			2006
	*(In millions)*
Net income	$	1,041		$	979
Non-cash charges		358			497
Pension trust contribution		(300	)		-
Working capital and other		52			(233	)
	$	1,151		$	1,243

	Nine Months Ended
	September 30,
Securities Issued or Redeemed	2007			2006
	*(In millions)*
New issues
Pollution control notes	$	-		$	253
Secured notes		-			382
Unsecured notes		1,100			600
	$	1,100		$	1,235
Redemptions
First mortgage bonds	$	287		$	1
Pollution control notes		4			311
Senior secured notes		203			181
Unsecured notes		153			500
Common stock		918			600
Preferred stock		-			107
	$	1,565		$	1,700

Short-term borrowings, net	$	(535	)	$	482

Borrowing Capability (In millions)
Short-term credit facilities⁽¹⁾	$	2,870
Accounts receivable financing facilities		550
Utilized		(570	)
LOCs		(337	)
Net available capability	$	2,513

	Revolving			Regulatory and
	Credit Facility			Other Short-Term
Borrower	Sub-Limit			Debt Limitations⁽¹⁾
	*(In millions)*
FirstEnergy	$	2,750		$	-	⁽²⁾
OE		500			500
Penn		50			41
CEI		250	⁽³⁾		500
TE		250	⁽³⁾		500
JCP&L		425			423
Met-Ed		250			250	⁽⁴⁾
Penelec		250			250	⁽⁴⁾
FES		250			-	⁽²⁾
ATSI		-	⁽⁵⁾		50

Summary of Cash Flows	Property
Provided from (Used for) Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	*(In millions)*
Nine Months Ended September 30, 2007
Energy delivery services	$	(609	)	$	34		$	(2	)	$	(577	)
Competitive energy services		(462	)		1,345			(1	)		882
Other		(56	)		(5	)		2			(59	)
Inter-Segment reconciling items		-			(15	)		-			(15	)
Total	$	(1,127	)	$	1,359		$	(1	)	$	231

Nine Months Ended September 30, 2006
Energy delivery services	$	(489	)	$	196		$	(8	)	$	(301	)
Competitive energy services		(473	)		(7	)		(1	)		(481	)
Other		(28	)		31			20			23
Inter-Segment reconciling items		-			(63	)		-			(63	)
Total	$	(990	)	$	157		$	11		$	(822	)

	Maximum
Guarantees and Other Assurances	Exposure
	*(In millions)*
FirstEnergy Guarantees of Subsidiaries
Energy and Energy-Related Contracts ⁽¹⁾	$	647
LOC (long-term debt) – interest coverage ⁽²⁾		9
Other ⁽³⁾		575
		1,231

Subsidiaries’ Guarantees
Energy and Energy-Related Contracts		37
LOC (long-term debt) – interest coverage ⁽²⁾		3
Other ⁽⁴⁾		2,686
		2,726

Surety Bonds		75
LOC (long-term debt) – interest coverage ⁽²⁾		5
LOC (non-debt) ⁽⁵⁾⁽⁶⁾		690

Total Guarantees and Other Assurances	$	4,727

	Three Months Ended									Nine Months Ended
Increase (Decrease) in the Fair Value	September 30, 2007									September 30, 2007
of Commodity Derivative Contracts	Non-Hedge			Hedge			Total			Non-Hedge			Hedge			Total
	*(In millions)*
Change in the Fair Value of
Commodity Derivative Contracts:
Outstanding net liability at beginning of period	$	(845	)	$	(12	)	$	(857	)	$	(1,140	)	$	(17	)	$	(1,157	)
Additions/change in value of existing contracts		(38	)		-			(38	)		69			(6	)		63
Settled contracts		47			5			52			235			16			251
Outstanding net liability at end of period ⁽¹⁾		(836	)		(7	)		(843	)		(836	)		(7	)		(843	)

Non-commodity Net Liabilities at End of Period:
Interest rate swaps ⁽²⁾		-			(8	)		(8	)		-			(8	)		(8	)
Net Liabilities - Derivative Contracts at End of Period	$	(836	)	$	(15	)	$	(851	)	$	(836	)	$	(15	)	$	(851	)

Impact of Changes in Commodity Derivative Contracts⁽³⁾
Income Statement effects (pre-tax)	$	4		$	-		$	4		$	4		$	-		$	4
Balance Sheet effects:
Other comprehensive income (pre-tax)	$	-		$	5		$	5		$	-		$	10		$	10
Regulatory assets (net)	$	(5	)	$	-		$	(5	)	$	(300	)	$	-		$	(300	)