GLOSSARY OF TERMS, Cont’d.

SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO2₂	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

PART I. FINANCIAL INFORMATION

ITEMS 1. AND 2. FINANCIAL STATEMENTS AND MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

Net income in the first quarter of 2008 was $276 million, or basic earnings of $0.91 per share of common stock ($0.90 diluted), compared with net income of $290 million, or basic and diluted earnings of $0.92 per share in the first quarter of 2007. The decrease in FirstEnergy’s earnings was driven primarily by increased operating expenses, partially offset by increased revenues.

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

Regulatory Matters - Ohio

Legislative Process

On April 22, 2008, an amended version of Substitute Senate Bill 221 (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. 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 products that are contracted for delivery two years into the 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 and energy efficiency, including requirements to meet annual benchmarks. FirstEnergy is currently evaluating this legislation and expects to file an ESP in the second or third quarter of 2008.

Distribution Rate Request

On February 25, 2008, evidentiary hearings concluded in the distribution rate requests for the Ohio Companies. The requests for $332 million in revenue increases were filed on June 7, 2007. Public hearings were held from March 5, 2008 through March 24, 2008. Main briefs were filed on March 28, 2008, and reply briefs were filed on April 18, 2008. The PUCO is expected to render its decision during the second or third quarter of 2008 (see Outlook – Ohio).

Regulatory Matters - Pennsylvania

Penn’s Interim Default Service Supply

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.

Met-Ed and Penelec Transmission Service Charge Filing

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.

Generation

Generation Output Record

FirstEnergy set a new first quarter generation output record of 20.4 million megawatt-hours, a 1.8% increase over the prior record established in the first quarter of 2006.

Refueling Outage

On April 14, 2008, Beaver Valley Unit 2 began its regularly scheduled refueling outage. During the outage, several improvement projects will take place on the 868-MW unit including replacing the high pressure turbine and inspecting the reactor vessel and other plant safety systems. Beaver Valley Unit 2 had operated for 520 consecutive days when it was taken off line for the outage.

Maintenance Outage

On April 14, 2008, the Perry Nuclear Power Plant returned to service following completion of a 10-day planned outage for valve work and other maintenance in preparation for the upcoming summer months.

Financial Matters

Acquisition of Additional Equity Interests in Beaver Valley Unit 2

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.

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.

Non-Core Asset Sale

On March 7, 2008, FirstEnergy sold substantially all of the assets of FirstEnergy Telecom Services, Inc. to FirstCom for $45 million in cash, with FirstCom also assuming related liabilities. The sale resulted in an after-tax gain of approximately $0.06 per share. FirstEnergy is a 15.6% shareholder in FirstCom.

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).

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.

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.

~~FIRSTENERGY CORP.~~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 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 2008 compared to 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

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 $37 million increase in FirstEnergy’s net income in the first three months of 2008 compared to the same period in 2007. The increase resulted from the sale of telecommunication assets ($19 million, net of taxes), reduced short-term disability costs ($8 million) and reduced interest expense ($11 million) associated with FirstEnergy’s revolving credit facility.

CAPITAL RESOURCES AND ~~SUBSIDIARIES~~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, 2007. 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 $356 million in the first three months of 2008 compared to $57 million used for operating activities in the first three months of 2007, as summarized in the following table:

	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.

	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 had approximately $1.6 billion of short-term indebtedness as of March 31, 2008 compared to approximately $903 million as of December 31, 2007. Available bank borrowing capability as of March 31, 2008 included the following:

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.

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.

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 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 and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

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

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.

FirstEnergy's regulated companies also have the 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 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 influenced by the ratings of its securities. The following table displays FirstEnergy’s, FES’ and the Companies’ securities ratings as of March 31, 2008. S&P’s outlook of FirstEnergy and its subsidiaries 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

Cash Flows From Investing Activities

Net cash flows used in investing activities resulted principally from property additions. Energy delivery services property additions primarily include expenditures related to transmission and 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 2007 by business segment:

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	)

Net cash used for investing activities in the first quarter of 2008 increased by $352 million compared to the first quarter of 2007. The increase was principally due to a $415 million increase in property additions, which reflects AQC system expenditures and the acquisition of a partially completed natural gas fired generating plant in Fremont, Ohio. Partially offsetting the increase in property additions were cash proceeds from the sale of telecommunication assets.

During the remaining three quarters of 2008, capital requirements for property additions and capital leases are expected to be approximately $1.4 billion. FirstEnergy and the 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 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 2008-2012 is expected to be approximately $7.6 billion (excluding nuclear fuel), of which approximately $2.0 billion applies to 2008. Investments for additional nuclear fuel during the 2008-2012 period are estimated to be approximately $1.4 billion, of which about $150 million applies to 2008. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $949 million and $111 million, respectively, as the nuclear fuel is consumed.

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 March 31, 2008, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.4 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 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 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 other FirstEnergy assets. The likelihood is remote that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with 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 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 $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.

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 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 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.

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 products that are contracted for delivery two years into the 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 require energy savings in excess of 22% by 2025. Requirements are in place to meet annual benchmarks for renewable energy resources and energy efficiency, subject to review by the PUCO. FirstEnergy is currently evaluating this legislation and expects to file an ESP in the second or third quarter of 2008.

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 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 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.

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.

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. A rehearing request by AEP is pending before the FERC.

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 $1.4 billion for the period 2008-2012.

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

Clean Air Act Compliance

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

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the CAA. FirstEnergy has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding 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. NOX reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOX reductions at FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

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

On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the 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 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 March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2). FirstEnergy's Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO2 and NOX emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on NOX 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. NOX emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOX 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 may depend on the outcome of this litigation and how CAIR is ultimately 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, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap and trade program. The EPA 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 mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W.H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, are referred to as the NSR cases.

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it 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. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate 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 CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities.

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

Clean Water Act

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

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

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, 2008, FirstEnergy had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of 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. 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 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.

Other Legal Proceedings

Power Outages and Related Litigation

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge 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 March 31, 2008.

Nuclear Plant Matters

On May 14, 2007, the Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information, about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC’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 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. A final order identifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. The court held a scheduling conference in April 2008 where it set a briefing schedule with 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.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 141(R) – “Business Combinations”

In December 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

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

In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on 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 Standard on its financial 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 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 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, 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 9, Note 3, Note 2(G) and Note 12 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 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.

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.

35

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.

36

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.

37

FIRSTENERGY SOLUTIONS CORP.

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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.

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 three months of 2008, net income decreased to $90 million from $103 million in the same period in 2007. The decrease in net income was primarily due to higher fuel and other operating expenses, partially offset by lower purchased power costs and higher revenues.

Revenues

Revenues increased by $81 million in the first three months of 2008 compared to the same period in 2007 due to increases in revenues from non-affiliated and affiliated wholesale sales, partially offset by lower retail generation sales. Retail generation sales revenues decreased as a result of decreased sales in the PJM market partially offset by increased sales in 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 lower customer usage. Non-affiliated wholesale revenues increased as a result of more generation available for wholesale sales to non-affiliates.

The increase in affiliated company wholesale sales was due to greater sales to the Ohio and Pennsylvania Companies to meet 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 due to a 45% increase in customer shopping in the first quarter of 2008 compared to the first quarter of 2007.

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

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

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

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 by $94 million in the first three months of 2008 compared with the same period of 2007. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first three months of 2008 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
$ 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.

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 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 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 three months of 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 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

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.

42

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 ~~AND SUBSIDIARIES~~

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 average prices across all customer classes, partially offset by decreased KWH sales to commercial and industrial customers. 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 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 KWH sales were lower due to 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 and revenues in the first three months of 2008 from the same period in 2007 are summarized in the following 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

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 ~~AND SUBSIDIARIES~~

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 absence of fuel costs in the first three months of 2008 was due to 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 prices, as provided for under the PSA with FES. Other operating costs were lower primarily due to the assignment of CEI’s leasehold interests in the Mansfield plant. Higher amortization of 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 change in deferrals of new regulatory assets was primarily due to lower deferred MISO expenses (more expenses currently recovered through increased transmission tariffs) and RCP fuel costs (implementation of fuel cost recovery rider). The change in general taxes is primarily due to higher real and personal property taxes.

Other Expense

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).

Legal Proceedings

New Accounting Standards and Interpretations

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 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

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.

THE TOLEDO EDISON COMPANY ~~AND SUBSIDIARY~~

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 ($26 million) and lower PSA sales to FES in the first three months of 2008 ($20 million) due to the assignment of TE’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 2 to NGC.

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 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 Analysis of Registrant Subsidiaries). The increase in sales volume reflects increased weather-related usage in the first three months of 2008 (heating degree days increased 3.3% from the same period of 2007).

Changes in retail electric generation KWH sales and revenues in the first three months of 2008 from the same period of 2007 are summarized in the following tables.

	Increase
Retail Generation KWH Sales	(Decrease)

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

Retail Generation Revenues Increase

(In millions)

Residential $ 4
Commercial 3
Industrial 4
Increase in Retail Generation Revenues $ 11

Revenues from distribution throughput increased by $4 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 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 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

Expenses

Total expenses decreased $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)
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 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 primarily due to lower interest expense, partially offset by lower investment income. The lower interest expense resulted from the redemption of long-term debt ($85 million principal amount) since the first quarter of 2007. The decrease in investment income resulted primarily from the principal repayments since the first quarter of 2007 on notes receivable from associated companies.

Legal Proceedings

New Accounting Standards and Interpretations

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 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.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 7, 2008

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.

60

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.

61

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.

JERSEY CENTRAL POWER & LIGHT COMPANY ~~AND SUBSIDIARIES~~

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

~~METROPOLITAN EDISON COMPANY AND SUBSIDIARIES~~

~~PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES~~Net income for the first three months of 2008 decreased to $34 million from $38 million in the same 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 wholesale generation revenues increased by $73 million and $38 million, respectively, in the first three months of 2008.

Retail generation revenues from all customer classes increased in the first three months of 2008 compared to 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 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 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 summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)

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:

	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.

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.

67

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:

	Increase
Retail Generation KWH Sales	(Decrease)

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

	Increase
Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	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	%
Commercial		4.1	%
Industrial		(1.8	)%
Net Increase in Distribution Deliveries		2.7	%

Distribution Revenues	Increase
	(In millions)
Residential	$	1
Commercial		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.

72

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	%
Commercial		3.0	%
Industrial		(1.6	)%
Net Increase in Retail Generation Sales		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)

Residential		4.5	%
Commercial		3.0	%
Industrial		(1.5	)%
Net Increase in Retail Generation Sales		2.1	%

Distribution Revenues Increase
(In millions)
Residential $ 2
Commercial 2
Industrial -
Increase in Retail Generation Revenues $ 4

PJM transmission revenues increased by $10 million in the first quarter of 2008 compared to the same period of 2007, primarily due to higher transmission volumes. Penelec defers the difference between revenue from its transmission rider and total transmission costs incurred, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses increased by $49 million in the first quarter of 2008 as compared with 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 $ 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 quarter of 2008, general taxes increased $2 million as compared to the same period of 2007, primarily due to higher gross receipts taxes.

Other Expense

In the first quarter of 2008, other expense increased primarily due to higher interest expense associated with Penelec’s $300 million senior note issuance in August 2007 and 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 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.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 7, 2008

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.

79

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.

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.

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 $137 million as of March 31, 2008 (JCP&L - $78 million and Met-Ed - $59 million). Regulatory assets not earning a current return are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed. The following table discloses regulatory assets by company:

*	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.

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. 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 2008 through 2010:

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

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 (OE - $91 million, CEI - $72 million and TE - $26 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 (OE - $114 million, CEI - $79 million and TE - $33 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 (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 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 (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 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.

·	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 (Applicable to FES, Met-Ed, Penelec, OE and Penn)

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, Met-Ed, Penelec, OE and Penn are unable to predict what impact, if any, such legislation may have on their operations.

New Jersey (Applicable to JCP&L)

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 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.

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, JCP&L cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations.

FERC Matters (Applicable to FES and each of the Companies)

Transmission Service between MISO and PJM

PJM Transmission Rate Design

Post Transition Period Rate Design

The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within the MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of 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

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. FES, CEI, OE, Penn and TE support 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 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 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.

MISO Resource Adequacy Proposal

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. FES and the Companies do not believe that 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, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FES and the Companies estimate capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.

FES and the Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in 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)

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

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

National Ambient Air Quality Standards (Applicable to FES)

In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2). FES' Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO2 and NOX 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. NOX emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOX 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 may depend on the outcome of this litigation and how CAIR is ultimately 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. 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’ only Pennsylvania coal-fired 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 NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FGCO, OE and Penn could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion for FGCO for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

Climate Change (Applicable to FES)

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 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 FES’ plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to 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 aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (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 studying various control options and their costs and effectiveness. Depending on the results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future 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, FES and the Companies must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, 2008, FES and the Companies had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy and FES (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.

Other Legal Proceedings

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 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 March 31, 2008.

Nuclear Plant Matters (Applicable to FES)

Other Legal Matters (Applicable to OE, JCP&L and FES)

New Accounting Standards and Interpretations (Applicable to FES and each of the Companies)

SFAS 141(R) – “Business Combinations”

In December 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FES or any of the Companies 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. FES and the 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”

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. 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's principal business~~FirstEnergy is ~~the holding,~~a diversified energy company that holds, directly or indirectly, of all of the outstanding common stock of its ~~eight~~ principal ~~electric utility operating~~ subsidiaries: OE, CEI, TE, Penn ~~ATSI, JCP&L, Met-Ed and Penelec. Penn is a~~(a wholly owned subsidiary of ~~OE. FirstEnergy’s consolidated financial statements also include its other subsidiaries:~~OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and its subsidiaries FGCO and NGC, and FESC.

FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, ~~2006~~2007 for FirstEnergy, FES and the Companies. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain ~~businesses divested in 2006~~prior year amounts have been ~~classified as discontinued operations on the Consolidated Statements of Income (see Note 3). As discussed in Note 12, interim period segment reporting in 2006 was~~ reclassified to conform ~~with~~to the current year ~~business segment organizations and operations.~~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 7)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) ~~are accounted for under~~follow the equity ~~method.~~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. ~~Certain prior year amounts~~

The consolidated financial statements as of March 31, 2008 and for the three-month periods ended March 31, 2008 and 2007 have been ~~reclassified to conform to the current year presentation.~~

~~FirstEnergy's and the Companies'~~reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting ~~firm has performed reviews~~firm. Their report (dated May 7, 2008) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and ~~issued reports~~they do not express an opinion on ~~these consolidated interim~~that unaudited financial ~~statements~~information. Accordingly, the degree of reliance on their report on such information should be restricted in ~~accordance with standards established by~~light of the ~~PCAOB. Pursuant~~limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to ~~Rule 436(c) under~~the liability provisions of Section 11 of the Securities Act of 1933 for their ~~reports~~report on the unaudited financial information because that report is not a “report” or a “part” of ~~those reviews should not be considered~~ a ~~report~~registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of ~~Section~~Sections 7 and 11 of ~~that~~the Securities Act ~~and the independent registered public accounting firm’s liability under Section 11 does not extend to them.~~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 August 10, 2006, FirstEnergy repurchased 10.6 million shares, approximately 3.2%, of its outstanding common stock through an accelerated share repurchase program. The initial purchase price was $600 million, or $56.44 per share. A final purchase price adjustment of $27 million was settled in cash on April 2, 2007. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an ~~additional~~ accelerated share repurchase program ~~with an affiliate of Morgan Stanley and Co., Incorporated~~ at an initial price of ~~$62.63 per share, or a total initial purchase price of~~ approximately $900 million. ~~The~~A final purchase price ~~for this program will be adjusted to reflect the volume weighted average price~~adjustment of ~~FirstEnergy’s common stock during the period of time that the bank will acquire shares to cover its short position, which is approximately one year.~~$51 million was settled in cash on December 13, 2007. The following table reconciles basic and diluted earnings per share ~~calculations for the first quarter~~ of 2007 reflect the impact associated with the March 2007 accelerated share repurchase program. FirstEnergy intends to settle, in cash or shares, any obligation on its part to pay the difference between the average of the daily volume-weighted average price of the shares as calculated under the March 2007 program and the initial price of the shares. The effect of any potential settlement in shares is currently unknown.common stock:

Reconciliation of Basic and Diluted

Three Months Ended
March 31,

Earnings per Share of Common Stock

2007

2006

(In millions, except per share amounts)
Income from continuing operations $ 290 $ 219
Discontinued operations - 2
Net income available for common shareholders $ 290 $ 221

Average shares of common stock outstanding - Basic 314 329
Assumed exercise of dilutive stock options and awards 2 1
Average shares of common stock outstanding - Dilutive 316 330

Earnings per share:
Basic earnings per share:
Earnings from continuing operations $ 0.92 $ 0.67
Discontinued operations - -
Net earnings per basic share $ 0.92 $ 0.67

Diluted earnings per share:
Earnings from continuing operations $ 0.92 $ 0.67
Discontinued operations - -
Net earnings per diluted share $ 0.92 $ 0.67

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

3. DIVESTITURES AND DISCONTINUED OPERATIONS

~~In 2006,~~On March 7, 2008, FirstEnergy sold ~~its remaining FSG subsidiaries (Roth Bros., Hattenbach, Dunbar, Edwards and RPC) for an aggregate~~certain telecommunication assets, resulting in a net after-tax gain of ~~$2.2~~$19.3 million. ~~Hattenbach, Dunbar, Edwards, and RPC are included in discontinued operations~~As a result of the sale, FirstEnergy adjusted goodwill by $1 million for the ~~quarter ended March 31, 2006; Roth Bros. does~~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 ~~that classification.~~classification as discontinued operations as of March 31, 2008.

In4. FAIR VALUE MEASURES

Effective January 1, 2008, FirstEnergy adopted SFAS 157, which provides a framework for measuring fair value under GAAP and, among other things, requires enhanced disclosures about assets and liabilities recognized at fair value. FirstEnergy also adopted SFAS 159 on January 1, 2008, which provides the option to measure certain financial assets and financial liabilities at fair value. FirstEnergy has analyzed its financial assets and financial liabilities within the scope of SFAS 159 and, as of March ~~2006, FirstEnergy sold 60% of its interest~~31, 2008, has elected not to record eligible assets and liabilities at fair value.

As defined in ~~MYR~~SFAS 157, fair value is the price that would be received for an ~~after-tax gain of $0.2 million. In June 2006, as part~~asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the ~~March agreement, FirstEnergy sold an additional 1.67% interest. As a result~~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 ~~March sale, FirstEnergy deconsolidated MYR~~reporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that are held in various trusts.

Level 2 – Pricing inputs are either directly or indirectly observable in the ~~first quarter~~market as of ~~2006~~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 ~~accounted~~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 ~~its remaining 38.33% interest under the equity method. In the fourth quarter of 2006, FirstEnergy sold its remaining MYR interest for an after-tax gain of $8.6 million. The income~~commodities, time value, volatility factors, and current market and contractual prices for the ~~period~~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 ~~MYR was accounted~~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 ~~as an equity method investment has not been included in discontinued operations; however, results~~the short term) and fundamental modeling (generally for the longer term). Key fundamental electricity model inputs are generally directly observable in the ~~first quarter~~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 ~~2006 prior~~consultants, reflect the consensus of appropriate FirstEnergy management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. FirstEnergy’s Level 3 instruments consist of NUG contracts.

FirstEnergy utilizes market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the ~~initial sale in March 2006, including~~valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. FirstEnergy primarily applies the ~~gain on~~market approach for recurring fair value measurements using the ~~sale, are reported as discontinued operations.~~best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs.

~~Revenues associated with discontinued operations were $140 million in first quarter of 2006.~~ The following table ~~summarizes~~sets forth FirstEnergy’s financial assets and financial liabilities that are accounted for at fair value by level within the ~~net income (loss) included~~fair value hierarchy as of March 31, 2008. As required by SFAS 157, assets and liabilities are classified in ~~"Discontinued Operations"~~their entirety based on the ~~Consolidated Statements~~lowest level of ~~Income~~input that is significant to the fair value measurement. FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	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, ~~2006~~2008 (in millions):

FSG subsidiaries $ (1 )
MYR 3
Income from discontinued operations $ 2

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 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.

4.5. 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 ~~the Company.~~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 ~~purchase~~purchases and normal sales ~~criterion.~~criteria. Derivatives that meet ~~that criterion~~those criteria are accounted for ~~on the accrual basis.~~at cost. The changes in the fair value of derivative instruments that do not meet the normal ~~purchase~~purchases and normal sales ~~criterion~~criteria are recorded as other expense, as AOCL, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness. FirstEnergy does not offset fair value for the right to reclaim collateral or the obligation to return collateral.

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

The net deferred losses of ~~$45~~$84 million included in AOCL as of March 31, ~~2007,~~2008, for derivative hedging activity, as compared to ~~the~~$75 million as of December 31, ~~2006 balance of $58 million of net deferred losses,~~2007, resulted from a net $9$21 million ~~decrease~~increase related to current hedging activity and a $4$12 million decrease due to net hedge losses reclassified ~~into~~to earnings during the three months ended March 31, ~~2007.~~2008. Based on current estimates, approximately $7$19 million (after tax) of the net deferred losses on derivative instruments in AOCL as of March 31, ~~2007 is~~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. ~~In prior years, FirstEnergy has unwound swaps, the gains and losses are amortized in earnings over the remaining maturity of each respective hedged security as adjustments to interest expense.~~ As of March 31, ~~2007,~~2008, FirstEnergy had interest rate swaps with an aggregate notional value of ~~$750~~$250 million and a fair value of ~~$(24)~~$5 million.

During ~~2006~~2007 and the first three months of ~~2007,~~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 ~~issuances~~issuance of variable-rate, short-term debt and fixed-rate, long-term debt securities ~~for~~by one or more of its subsidiaries ~~during 2007 - 2008~~ as outstanding debt ~~matures.~~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 ~~2007,~~2008, FirstEnergy terminated swaps with a notional value of ~~$250~~$300 million ~~for which it~~and entered into swaps with a notional value of $500 million. FirstEnergy paid $3$18 million ~~all~~related to the terminations, $1 million of which was deemed ~~effective.~~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, ~~2007,~~2008, FirstEnergy had forward swaps with an aggregate notional amount of ~~$475~~$600 million and a ~~long-term debt securities~~ fair value of ~~$(2)~~$(8) million.

5.6. ASSET RETIREMENT OBLIGATIONS

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

The ARO liability of ~~$1.2~~$1.3 billion as of March 31, ~~2007~~2008 is primarily related to the future nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. ~~The obligation to decommission these units was developed based on site specific studies performed by an independent engineer.~~ FirstEnergy 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, ~~2007,~~2008, the fair value of the decommissioning trust assets was approximately $2.0 billion.

398

The following tables analyze changes to the ARO balance during the first quarters of ~~2007~~2008 and ~~2006,~~2007, respectively.

ARO Reconciliation	FirstEnergy		OE		CEI		TE		JCP&L		Met-Ed		Penelec		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
	*(In millions)*
Balance, January 1, 2007	$	1,190	$	88	$	2	$	27	$	84	$	151	$	77	$	1,190	$	760	$	88	$	2	$	27	$	84	$	151	$	77
Liabilities incurred		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-
Accretion		18		1		-		-		2		2		1		18		12		1		-		-		2		2		1
Revisions in estimated cash flows		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-
Balance, March 31, 2007	$	1,208	$	89	$	2	$	27	$	86	$	153	$	78	$	1,208	$	772	$	89	$	2	$	27	$	86	$	153	$	78

Balance, January 1, 2006	$	1,126	$	83	$	8	$	25	$	80	$	142	$	72
Liabilities incurred		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-
Accretion		18		1		-		-		1		2		1
Revisions in estimated cash flows		4		-		-		-		-		-		-
Balance, March 31, 2006	$	1,148	$	84	$	8	$	25	$	81	$	144	$	73

~~On May 8, 2007, the Ohio Companies filed with the PUCO a notice of intent to file~~request for an increase in electric distribution ~~rates. The Ohio Companies intend to file the application and rate request~~rates with the PUCO on ~~or after~~ June 7, 2007. The requested ~~$334 million~~ 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. 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 ~~subject to evidentiary hearings at the PUCO,~~ would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

109

·	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~~ ~~(Applicable~~A utility could also simultaneously file an MRO in which it would have to ~~Met-Ed, Penelec~~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 ~~Penn)~~the ability to mitigate market power, and a published source exists that identifies information for traded electricity and energy products that are contracted for delivery two years into the 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 require energy savings in excess of 22% by 2025. Requirements are in place to meet annual benchmarks for renewable energy resources and energy efficiency, subject to review by the PUCO. FirstEnergy is currently evaluating this legislation and expects to file an ESP in the second or third quarter of 2008.

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 costs during the term of these agreements with FES.

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

~~107~~

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 allows Met-Ed and Penelec to sell the output of NUG ~~generation~~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 have also separately terminated~~fixed price under the ~~tolling, suspension and supplier master agreements in connection with~~agreement is expected to remain below wholesale market prices during the ~~restatement~~term 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.~~

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.

110

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 in accordance with the April 7, 2006 tolling agreement described above.~~out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs ~~but only for those costs~~ incurred during 2006. In this rate filing, Met-Ed and Penelec ~~also~~ requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. 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 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 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. 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 ~~FirstEnergy’s and their financial condition and~~the results of ~~operations.~~operations of Met-Ed, Penelec and FirstEnergy.

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As of March 31, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $472 million and $124 million, respectively. Penelec’s $124 million deferral is subject to final resolution of an IRS settlement associated with NUG trust fund proceeds. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of 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 late 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 may file exceptions to the initial decision by May 22, 2007 and parties may reply to those exceptions 10 days thereafter. 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 would 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. The PPUC is requested to act on the proposal no later than November 2007 for the initial RFP to take place in January 2008.

On February 1, 2007, the Governor of Pennsylvania proposed an ~~Energy Independence Strategy (EIS).~~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 ~~through~~that results in the “lowest reasonable rate on a ~~"Least Cost Portfolio",~~long-term basis,” the utilization of micro-grids and ~~an optional~~a three year phase-in of rate increases. ~~Since~~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 ~~only recently~~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 ~~proposed, the~~introduced to address generation procurement, expiration of rate caps, conservation and renewable energy. The final form of ~~any~~this pending legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

~~New Jersey~~ (D) NEW JERSEY~~(Applicable to JCP&L)~~

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

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, ~~2007,~~2008, the accumulated deferred cost balance totaled approximately ~~$357~~$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.

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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 ~~Energy Master Plan (EMP),~~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;~~

·	~~Unit prices for electricity should remain no more than +5% of the regional average price (region~~ ~~includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia); and~~

·	~~Eliminate transmission congestion by 2020.~~

~~Comments on the objectives and participation in the development of the EMP have been solicited and~~ a number of working groups ~~have been formed~~ to 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 and 2) renewables have completed their assigned tasks of data gathering and analysis. Both groups have provided a report to the EMP Committee. The working groups addressing reliability and pricing issues continue their data gathering and analysis activities. 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~~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);

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·	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 ~~summer of 2007. A final draft of the EMP~~public comment period which is expected to extend into July 2008, a final EMP will be ~~presented~~issued to ~~the Governor in the fall of 2007 with further public hearings anticipated in early 2008.~~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, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. ~~A meeting~~Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal ~~was~~were held ~~on February 15, 2007.~~and additional, revised informal proposals were subsequently circulated by the Staff. On ~~February 22,~~September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU ~~Staff circulated~~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 revised proposal upon which discussions with interested stakeholders were held on March 26, 2007. On April 18 and April 23, 2007 the NJBPU staff circulated further revised draft proposals. A schedule for formal proceedings has not yet been established. At this time, FirstEnergy cannot predict the outcome of this process nor determine thematerial impact ~~if any, ultimate regulations resulting from these draft proposals may have~~ on its operations or those of JCP&L.

(E) FERC ~~Matters~~ MATTERS

~~(Applicable to 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. ~~JCP&L, Met-Ed and Penelec participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges.~~ The ~~Presiding Judge~~presiding judge issued an ~~Initial Decision~~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~~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 ~~2007.~~2008.

PJM Transmission Rate Design

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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~~Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in opposition proposing to create a "postage stamp", or average rate for all high voltage transmission facilities across ~~PJM. Second,~~PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to refund and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearingeffect of shifting recovery of the May 31, 2005 order. On March 20, 2006, a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued an order approving this settlement on April 19, 2006. Hearings in the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial Decision was issued by the ALJ. The ALJ adopted the FERC Trial Staff’s position that the costcosts 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.~~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 ~~rejecting the ALJ’s findings and recommendations in nearly every respect. 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 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 ~~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.

~~On February 15, 2007, MISO~~ 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 documents with the FERC to establish a market-based, competitive ancillary services market. MISO contends that the filing will integrate operating reserves into MISO’s existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch. The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO. MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region with an implementation in the second or third quarter of 2008. FirstEnergy filed comments on ~~March 23, 2007, supporting the ancillary service market in concept, but proposing certain changes in MISO’s proposal. MISO has requested FERC action on its filing by June 2007.~~

On February 16, 2007, the FERC issued a final rule that revises its decade-old open access transmission regulations and policies. The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule will become effective on MaySeptember 14, 2007. The ~~final rule has not yet~~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 ~~fully evaluated to assess its impact on FirstEnergy’s operations. MISO and PJM will be filing revised tariffs to comply with FERC’s order.~~

~~Environmental Matters~~~~(Applicable to each of the Companies)~~

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

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~~Regulation of Hazardous Waste~~

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2007, 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 $87 million (JCP&L - $59 million, TE - $3 million, CEI - $1 million, and other subsidiaries - $24 million) have been accrued through March 31, 2007.

~~W. H. Sammis Plant~~ ~~(Applicable to OE and Penn)~~

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

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the New Source Review litigation. This settlement agreement, which is in the form of a consent decree, was approved by the Court on July 11, 2005, and requires reductions of NO_X ~~and SO~~₂ emissions at the W. H. Sammis Plant and other FES coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation are currently estimated to be $1.5 billion for FGCO ($400 million of which is expected to be spent during 2007, with the largest portion of the remaining $1.1 billion expected to be spent in 2008 and 2009).

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

~~On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of SO~~₂ ~~emissions. FGCO also entered into an agreement with B&W on August 25, 2006 to supply flue gas desulfurization systems for the reduction of SO~~₂ ~~emissions. Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions also are being installed at the W.H. Sammis Plant under a 1999 agreement with B&W.~~

~~Other Legal Proceedings~~~~(Applicable to each of the Companies)~~

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

~~Power Outages and Related Litigation~~

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In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision on July 8, 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, New Jersey. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, on March 7, 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. In late March 2007, JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of March 31, 2007.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

FirstEnergy companies also are defending 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., 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 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.

113

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 ~~October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid~~August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to ~~numerous insureds who allegedly suffered losses as~~retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the ~~August 14, 2003 outages. All~~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 ~~insureds appear to~~cost of new 345 kV and higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006. On January 18, 2007, the Court granted the Companies’ motion to dismiss the case. It is unknown whether or not the matter will be further appealed. No estimate of potential liability is available for any of these cases.

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

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

~~Other Legal Matters~~retained.

On ~~August 22, 2005,~~September 17, 2007, AEP filed a ~~class action~~ complaint ~~was filed against OE in Jefferson County, Ohio Common Pleas Court,~~under Sections 206 and 306 of the Federal Power Act seeking ~~compensatory~~to have the entire transmission rate design and ~~punitive damages~~cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be 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 andrecovered in the ~~institution of~~local utility transmission rate zone through a ~~medical monitoring program for class members.~~license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On ~~April 5, 2007,~~January 31, 2008, 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. The Court has scheduled oral argument for June 25, 2007 to hear the plaintiffs' request for reconsideration of itsFERC issued an order denying ~~class certification and~~the complaint. A rehearing request ~~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 thatby AEP is pending before the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. JCP&L intends to re-file an appeal in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

If it were ultimately determined that FirstEnergy or the Companies 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 the Companies’ financial condition, results of operations and cash flows.FERC.

~~New Accounting Standards and Interpretations~~~~(Applicable to each~~Distribution of ~~the Companies)~~MISO Network Service Revenues

~~SFAS 159 - “The Fair Value Option~~Effective February 1, 2008, the MISO Transmission Owners Agreement provides for ~~Financial Assets~~a change in the method of distributing transmission revenues among the transmission owners. MISO and ~~Financial Liabilities - Including~~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.

On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of ~~FASB~~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.

~~Statement No. 115”~~MISO Ancillary Services Market and Balancing Area Consolidation

InMISO 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 ~~2007,~~25, 2008, the ~~FASB~~FERC issued ~~SFAS 159, which provides companies with~~ an ~~option~~order approving the ASM subject to ~~report selected financial assets and liabilities at fair value. The Standard requires companies to provide additional information~~certain compliance filings. MISO has since notified the FERC that ~~will help investors and other users~~the start of ~~financial statements to more easily understand the effect~~its ASM is delayed until September 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. The Companies are currently evaluating the impact of this Statement on their respective financial statements.2008.

114

Duquesne’s Request to Withdraw from PJM

MISO Resource Adequacy Proposal

Organized Wholesale Power Markets

115

12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS ~~157 - “Fair Value Measurements”~~141(R) – “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~~tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

SFAS 160 - “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 ~~expanded disclosures about fair value measurements. The key changes to current practice are: (1)~~ the ~~definition~~deconsolidation of ~~fair value which focuses on~~a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ~~exit price rather than entry price; (2)~~ownership interest in the ~~methods used to measure fair value such~~consolidated entity that should be reported as ~~emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as~~equity in the ~~inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements.~~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. The Companies are currently evaluating the impact of this Statement on their respective financial statements.~~

~~EITF 06-10 - “Accounting for Deferred Compensation and Postretirement Benefit Aspects of Collateral~~

~~Split-Dollar Life Insurance Arrangements”~~

In March 2007, the EITF reached a final consensus on Issue 06-10 concluding that an employer should recognize a liability for the postretirement obligation associated with a collateral assignment split-dollar life insurance arrangement if, based on the substantive arrangement with the employee, the employer has agreed to maintain a life insurance policy during the employee’s retirement or provide the employee with a death benefit. The liability should be recognized in accordance with SFAS 106if, in substance, a postretirement plan exists or APB 12 if the arrangement is, in substance, an individual deferred compensation contract. The EITF also reached a consensus that the employer should recognize and measure the associated asset on the basis of the terms of the collateral assignment arrangement. This pronouncement is effective for fiscal years, beginning on or after December 15, ~~2007, including interim periods within those years.~~2008. Early adoption is prohibited. The ~~Companies do~~Statement is not ~~expect this pronouncement~~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 requires enhancements to 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 is intended to better convey the 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 ~~respective~~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 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 financial statements locate important information about derivative instruments. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

13. SEGMENT INFORMATION

FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The “Other” segment primarily consists of telecommunications services. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”

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

The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive 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.

~~115~~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

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.

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 March 31, ~~2007,~~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~~reporting.

~~116~~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 910 and 1011 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 March 31, ~~2007,~~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
	January 1-31,	February 1-28,	March 1-31,	First	January 1-31,	February 1-29,	March 1-31,	First
	2007	2007	2007	Quarter	2008	2008	2008	Quarter
Total Number of Shares Purchased ^(a)	62,469	226,418	15,272,836	15,561,723	329,106	16,853	988,386	1,334,345
Average Price Paid per Share	$59.61	$63.78	$62.69	$62.69	$76.56	$71.68	$68.55	$70.57
Total Number of Shares Purchased
As Part of Publicly Announced Plans
or Programs ^(b)	-	-	14,370,110	14,370,110	-	-	-	-
Maximum Number (or Approximate Dollar
Value) of Shares that May Yet Be
Purchased Under the Plans or Programs	16,000,000	16,000,000	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.

125

ITEM 6.EXHIBITS

Exhibit Number
Exhibit Number

~~FirstEnergy~~

	~~10.1~~		~~Confirmation dated March 1, 2007 between FirstEnergy Corp. and Morgan Stanley and Co.,~~ ~~International Limited~~ ⁽¹⁾
			~~10.2~~	~~Form of U.S. $250,000,000 Credit Agreement, dated as of March 2, 2007, between FirstEnergy~~ ~~Corp., as Borrower, and Morgan Stanley Senior Funding, Inc., as Lender.~~ FirstEnergy⁽²⁾
	~~10.3~~	~~Form of Guaranty dated as of March 2, 2007, between FirstEnergy Corp., as Guarantor, and~~ ~~Morgan Stanley Senior Funding, Inc., as Lender under a U.S. $250,000,000 Credit Agreement,~~ ~~dated as of March 2, 2007, with FirstEnergy Solutions Corp., as Borrower.~~
		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-15(e)/15d-(e).~~13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule ~~13a-15(e)/15d-(e).~~13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section ~~1350.~~
1350

~~117~~

FES
			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
			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
			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
			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-15(e)/15d-(e).~~13a-14(a)
			31.2	Certification of chief financial officer, as adopted pursuant to Rule ~~13a-15(e)/15d-(e).~~13a-14(a)
			32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section ~~1350.~~

~~CEI~~

	4	~~Officer’s Certificate (including the form of 5.70% Senior Notes due 2017), dated as of March 27,~~ ~~2007(Form 8-K dated March 28, 2007, Exhibit 4).~~
	~~31.1~~	~~Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).~~
	~~31.2~~	~~Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).~~
	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-15(e)/15d-(e).~~
	~~31.2~~	~~Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).~~
	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-15(e)/15d-(e).~~
	~~31.2~~	~~Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).~~
	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-15(e)/15d-(e).~~
	~~31.2~~	~~Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).~~
	32	~~Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.~~

~~Penelec~~

	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-15(e)/15d-(e).~~
	~~31.2~~	~~Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).~~
	32	~~Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.~~

⁽¹⁾	~~Confidential treatment has been requested for certain portions of the Exhibit. Omitted portions have been filed~~ ~~separately with the SEC.~~

⁽²⁾

~~A substantially similar agreement, dated as of the same date and in the same amount, was executed and delivered by~~

~~the registrant’s subsidiary, FirstEnergy Solutions Corp., for which the registrant provided its guaranty in the form filed as~~

~~Exhibit 10.2 above, all as described in the registrant’s Form 8-K filed March 5, 2007.~~

1350

Pursuant to reporting requirements of respective financings, FirstEnergy, 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.

~~118~~126

~~SIGNATURE~~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.

May ~~9, 2007~~8, 2008

	FIRSTENERGY CORP.
	Registrant

	~~OHIO EDISON COMPANY~~ FIRSTENERGY SOLUTIONS CORP.
	Registrant

	~~THE CLEVELAND ELECTRIC~~
	~~ILLUMINATING~~OHIO EDISON COMPANY
	Registrant

	THE ~~TOLEDO EDISON~~CLEVELAND ELECTRIC
	ILLUMINATING COMPANY
	Registrant

	~~JERSEY CENTRAL POWER & LIGHT~~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)

~~119~~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~~3402~~

~~1-2578~~ 333-145140-01	~~OHIO EDISON COMPANY~~ FIRSTENERGY SOLUTIONS CORP.	~~34-0437786~~ 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~~3402~~

1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	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~~3402~~

1-3583	THE TOLEDO EDISON COMPANY	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~~3402~~

1-3141	JERSEY CENTRAL POWER & LIGHT COMPANY	21-0485010
	(A New Jersey Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	~~c/o FirstEnergy Corp.~~
	~~76 South Main Street~~
	~~Akron, OH 44308~~
	Telephone (800)736--3402~~3402~~

1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(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~~3402~~

1-3522	PENNSYLVANIA ELECTRIC COMPANY	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~~3402~~

Yes ~~Yes~~ (X) No ~~( )~~ No ( )	FirstEnergy Corp., Ohio Edison 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 MAY ~~9, 2007~~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	~~15,009,335~~14,421,637
Metropolitan Edison Company, no par value	859,500
Pennsylvania Electric Company, $20 par value	~~5,290,596~~4,427,577

Jersey Central Power & Light Company		Pages

	Management's Narrative Analysis of Results of Operations	63-64
	Report of Independent Registered Public Accounting Firm	6365
	~~Management's Discussion~~Consolidated Statements of Income and ~~Analysis~~Comprehensive Income	66
	Consolidated Balance Sheets	67
	Consolidated Statements of ~~Financial Condition and Results of Operations~~Cash Flows	~~64-67~~68

~~The Cleveland Electric Illuminating~~Metropolitan Edison Company

	~~Consolidated Statements~~Management's Narrative Analysis of ~~Income and Comprehensive Income~~Results of Operations	68
	~~Consolidated Balance Sheets~~	69
	~~Consolidated Statements of Cash Flows~~	7069-70
	Report of Independent Registered Public Accounting Firm	71
	~~Management's Discussion~~Consolidated Statements of Income and ~~Analysis~~Comprehensive Income	72
	Consolidated Balance Sheets	73
	Consolidated Statements of ~~Financial Condition and Results of Operations~~Cash Flows	~~72-75~~74

~~The Toledo Edison~~Pennsylvania Electric Company

	~~Consolidated Statements~~Management's Narrative Analysis of ~~Income and Comprehensive Income~~Results of Operations	76
	~~Consolidated Balance Sheets~~	77
	~~Consolidated Statements of Cash Flows~~	7875-76
	Report of Independent Registered Public Accounting Firm	79
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	~~80-82~~

		Pages
Glossary of Terms		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~~Operations.

FirstEnergy Corp.

	~~Notes to~~ Management's Discussion and Analysis of Financial Condition and	1-32
	Results of Operations
	Report of Independent Registered Public Accounting Firm	33
	Consolidated ~~Financial~~ Statements of Income	~~1-21~~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~~Results of Operations	22
	~~Consolidated Statements of Comprehensive Income~~	23
	~~Consolidated Balance Sheets~~	24
	~~Consolidated Statements of Cash Flows~~	2538-40
	Report of Independent Registered Public Accounting Firm	2641
	~~Management's Discussion~~Consolidated Statements of Income and ~~Analysis~~Comprehensive Income	42
	Consolidated Balance Sheets	43
	Consolidated Statements of ~~Financial Condition and Results of Operations~~Cash Flows	~~27-59~~44

Ohio Edison Company

	Management's Narrative Analysis of Results of Operations	45-46
	Report of Independent Registered Public Accounting Firm	47
	Consolidated Statements of Income and Comprehensive Income	48
	Consolidated Balance Sheets	49
	Consolidated Statements of Cash Flows	50

The Cleveland Electric Illuminating Company

	Management's Narrative Analysis of Results of Operations	51-52
	Report of Independent Registered Public Accounting Firm	53
	Consolidated Statements of Income and Comprehensive Income	54
	Consolidated Balance Sheets	55
	Consolidated Statements of Cash Flows	56

The Toledo Edison Company

	Management's Narrative Analysis of Results of Operations	57-58
	Report of Independent Registered Public Accounting Firm	59
	Consolidated Statements of Income and Comprehensive Income	60
	Consolidated Balance Sheets	61
	Consolidated Statements of Cash Flows	62

		~~Pages~~


~~Jersey Central Power & Light Company~~
		77
	Consolidated Statements of Income and Comprehensive Income	8378
	Consolidated Balance Sheets	8479
	Consolidated Statements of Cash Flows	85
	~~Report of Independent Registered Public Accounting Firm~~	86
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	~~87-89~~80

~~Metropolitan Edison Company~~Combined Management’s Discussion and Analysis of Registrant Subsidiaries		81-94

Combined Notes to Consolidated Financial Statements		95-123
		~~Consolidated Statements of Income and Comprehensive Income~~	90
Item 3. Quantitative and Qualitative Disclosures About Market Risk.		~~Consolidated Balance Sheets~~	91
	~~Consolidated Statements of Cash Flows~~	92
	~~Report of Independent Registered Public Accounting Firm~~	93
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	~~94-96~~124

~~Pennsylvania Electric Company~~Item 4. Controls and Procedures – FirstEnergy.		124

Item 4T. Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.		124

		~~Consolidated Statements of Income and Comprehensive Income~~	97
	~~Consolidated Balance Sheets~~	98
	~~Consolidated Statements of Cash Flows~~	99
	~~Report of Independent Registered Public Accounting Firm~~	~~100~~
	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~	~~101-103~~

~~Combined Management’s Discussion and Analysis of Registrant Subsidiaries~~		~~104-115~~

~~Item 3.~~~~Quantitative and Qualitative Disclosures About Market Risk~~		~~116~~

~~Item 4.~~~~Controls and Procedures~~		~~116~~

Part II.Other Information

Item 1.Legal ~~Proceedings~~Proceedings.		~~117~~125

Item 1A.Risk ~~Factors~~Factors.		~~117~~125

Item 2.Unregistered Sales of Equity Securities and Use of ~~Proceeds~~Proceeds.		~~117~~125

Item 6.~~Exhibits~~ Exhibits.		~~117-118~~126

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
~~Centerior~~	~~Centerior Energy Corporation, former parent of CEI and TE, which merged with OE to form~~ ~~FirstEnergy on November 8, 1997~~
Companies	OE, CEI, TE, 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~~American Electric Power Company, Inc.
AOCL	Accumulated Other Comprehensive Loss
~~APB~~AQC	Air Quality Control
ARB	Accounting ~~Principles Board~~
~~APB 12~~Research Bulletin	~~APB Opinion No. 12, “Omnibus Opinion - 1967”~~
ARO	Asset Retirement Obligation
~~B&W~~	~~Babcock & Wilcox Company~~
~~Bechtel~~ASM	~~Bechtel Power Corporation~~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
CO2₂	Carbon Dioxide
DFI	Demand for Information
DOJ	United States Department of Justice
DRA	Division of Ratepayer Advocate
~~ECAR~~EIS	~~East Central Area Reliability Coordination Agreement~~Energy Independence Strategy
EITF	Emerging Issues Task Force
~~EITF 06-10~~EMP	~~EITF Issue No. 06-10, “Accounting for Deferred Compensation and Postretirement Benefit~~ ~~Aspects of Collateral Split-Dollar Life Insurance Arrangements”~~ 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 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
FIN 48	FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109”
~~Fitch~~FirstCom	~~Fitch Ratings, Ltd.~~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
~~NOAC~~	~~Northwest Ohio Aggregation Coalition~~
NOPR	Notice of Proposed Rulemaking
NOV	Notice of Violation
NOX_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 Consumer’s Counsel~~Counter
OVEC	Ohio Valley Electric Corporation
~~PCAOB~~PCRB	~~Public Company Accounting Oversight Board~~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 ~~Agreements~~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
~~RTC~~	~~Regulatory Transition Charge~~
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 106~~	~~SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”~~
~~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 141(R)	SFAS No 141(R), “Business Combinations”
SFAS 143	SFAS No. 143, ~~"Accounting~~“Accounting for Asset Retirement ~~Obligations"~~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”

	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	)

	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	)

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.

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.

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

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

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.

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.

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

Reconciliation of Basic and Diluted				Three Months Ended March 31,
Earnings per Share of Common Stock				2007		2006
			*(In millions, except per share amounts)*
Income from continuing operations				$	290	$	219
Discontinued operations					-		2
Net income available for common shareholders				$	290	$	221

Average shares of common stock outstanding - Basic					314		329
Assumed exercise of dilutive stock options and awards					2		1
Average shares of common stock outstanding - Dilutive					316		330

Earnings per share:
	Basic earnings per share:
		Earnings from continuing operations		$	0.92	$	0.67
		Discontinued operations			-		-
		Net earnings per basic share		$	0.92	$	0.67

	Diluted earnings per share:
		Earnings from continuing operations		$	0.92	$	0.67
		Discontinued operations			-		-
		Net earnings per diluted share		$	0.92	$	0.67

FSG subsidiaries	$	(1	)
MYR		3
Income from discontinued operations	$	2

	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	2007			2006			2007			2006			2008			2007			2008			2007
				*(In millions)*									(In millions)
Service cost	$	21		$	21		$	5		$	9		$	21		$	21		$	5		$	5
Interest cost		71			66			17			26			72			71			18			17
Expected return on plan assets		(112	)		(99	)		(13	)		(12	)		(115	)		(112	)		(13	)		(13	)
Amortization of prior service cost		2			2			(37	)		(19	)		2			2			(37	)		(37	)
Recognized net actuarial loss		10			15			12			14			1			10			12			12
Net periodic cost (credit)	$	(8)		$	5		$	(16	)	$	18		$	(19	)	$	(8)		$	(15	)	$	(16	)

	Pension Benefit Cost (Credit)						Other Postretirement Benefit Cost (Credit)					Pension Benefit Cost (Credit)						Other Postretirement Benefit Cost (Credit)
	2007			2006			2007			2006		2008			2007			2008			2007
				*(In millions)*								(In millions)
FES												$	4		$	-		$	(2	)	$	-
OE	$	(4.0	)	$	(1.5	)	$	(2.7	)	$	4.2		(7	)		(4	)		(2	)		(3	)
CEI		0.3			1.0			1.0			2.8		(1	)		-			1			1
TE		-			0.2			1.2			2.0		(1	)		-			1			1
JCP&L		(2.1	)		(1.4	)		(4.0	)		0.6		(4	)		(2	)		(4	)		(4	)
Met-Ed		(1.7	)		(1.7	)		(2.5	)		0.7		(3	)		(2	)		(3	)		(2	)
Penelec		(2.6	)		(1.3	)		(3.2	)		1.8		(3	)		(3	)		(3	)		(3	)
Other FirstEnergy subsidiaries		2.5			9.9			(5.7	)		6.1		(4	)		3			(3	)		(6	)
	$	(7.6	)	$	5.2		$	(15.9	)	$	18.2	$	(19	)	$	(8	)	$	(15	)	$	(16	)

	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

	Three Months Ended
	March 31,
	2007		2006
	*(In millions)*
JCP&L	$	20	$	15
Met-Ed		15		16
Penelec		8		8
	$	43	$	39

			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)
March 31, 2007
External revenues	$	2,040	$	328	$	619		$	12		$	(26	)	$	2,973
Internal revenues		-		714		-			-			(714	)		-
Total revenues		2,040		1,042		619			12			(740	)		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

March 31, 2006
External revenues	$	1,796	$	355	$	543		$	28		$	(17	)	$	2,705
Internal revenues		9		611		-			-			(620	)		-
Total revenues		1,805		966		543			28			(637	)		2,705
Depreciation and amortization		258		46		(21	)		1			5			289
Investment income		84		15		-			-			(56	)		43
Net interest charges		99		44		-			1			16			160
Income taxes		126		21		20			(6	)		(26	)		135
Income from
continuing operations		189		32		30			12			(44	)		219
Discontinued operations		-		-		-			2			-			2
Net income		189		32		30			14			(44	)		221
Total assets		23,633		6,759		215			367			823			31,797
Total goodwill		5,916		24		-			-			-			5,940
Property additions		193		244		-			-			10			447

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	*(In millions, except per share amounts)*
REVENUES:
Electric utilities	$	2,681		$	2,340
Unregulated businesses		292			365
Total revenues*		2,973			2,705

EXPENSES:
Fuel and purchased power		1,121			998
Other operating expenses		749			754
Provision for depreciation		156			148
Amortization of regulatory assets		251			221
Deferral of new regulatory assets		(144	)		(80	)
General taxes		203			193
Total expenses		2,336			2,234

OPERATING INCOME		637			471

OTHER INCOME (EXPENSE):
Investment income		33			43
Interest expense		(185	)		(165	)
Capitalized interest		5			7
Subsidiaries’ preferred stock dividends		-			(2	)
Total other expense		(147	)		(117	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		490			354

INCOME TAXES		200			135

INCOME FROM CONTINUING OPERATIONS		290			219

Discontinued operations (net of income tax benefit of $1 million)
(Note 3)		-			2

NET INCOME	$	290		$	221

BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income from continuing operations	$	0.92		$	0.67
Discontinued operations (Note 3)		-			-
Net income	$	0.92		$	0.67

WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		314			329

DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income from continuing operations	$	0.92		$	0.67
Discontinued operations (Note 3)		-			-
Net income	$	0.92		$	0.67

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		316			330

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.50		$	0.45


* Includes $104 million and $99 million of excise tax collections in the first quarter of 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
	March 31,
	2007			2006
	*(In millions)*

NET INCOME	$	290		$	221

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(11	)		-
Unrealized gain on derivative hedges		21			37
Unrealized gain on available for sale securities		17			37
Other comprehensive income		27			74
Income tax expense related to other comprehensive income		9			27
Other comprehensive income, net of tax		18			47

COMPREHENSIVE INCOME	$	308		$	268


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)
	March 31,			December 31,
	2007			2006
	*(In millions)*
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	89		$	90
Receivables-
Customers (less accumulated provisions of $40 million and
$43 million, respectively, for uncollectible accounts)		1,250			1,135
Other (less accumulated provisions of $23 million and
$24 million, respectively, for uncollectible accounts)		184			132
Materials and supplies, at average cost		591			577
Prepayments and other		233			149
		2,347			2,083
PROPERTY, PLANT AND EQUIPMENT:
In service		24,223			24,105
Less - Accumulated provision for depreciation		10,191			10,055
		14,032			14,050
Construction work in progress		754			617
		14,786			14,667
INVESTMENTS:
Nuclear plant decommissioning trusts		2,008			1,977
Investments in lease obligation bonds		775			811
Other		742			746
		3,525			3,534
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,898			5,898
Regulatory assets		4,371			4,441
Pension assets		277			-
Other		586			573
		11,132			10,912
	$	31,790		$	31,196
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	2,093		$	1,867
Short-term borrowings		2,247			1,108
Accounts payable		625			726
Accrued taxes		413			598
Other		1,020			956
		6,398			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		5,574			6,466
Accumulated other comprehensive loss		(241	)		(259	)
Retained earnings		2,941			2,806
Unallocated employee stock ownership plan common stock-
324,738 and 521,818 shares, respectively		(5	)		(10	)
Total common stockholders' equity		8,299			9,035
Long-term debt and other long-term obligations		8,546			8,535
		16,845			17,570
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,826			2,740
Asset retirement obligations		1,208			1,190
Power purchase contract loss liability		1,063			1,182
Retirement benefits		920			944
Lease market valuation liability		745			767
Other		1,785			1,548
		8,547			8,371
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
	$	31,790		$	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)

	Three Months Ended
	March 31,
	2007			2006
	*(In millions)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	290		$	221
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		156			148
Amortization of regulatory assets		251			222
Deferral of new regulatory assets		(144	)		(80	)
Nuclear fuel and lease amortization		26			20
Deferred purchased power and other costs		(116	)		(104	)
Deferred income taxes and investment tax credits, net		53			6
Investment impairment		5			-
Deferred rents and lease market valuation liability		(25	)		(38	)
Accrued compensation and retirement benefits		(65	)		(19	)
Commodity derivative transactions, net		1			26
Income from discontinued operations		-			(2	)
Cash collateral		6			(106	)
Pension trust contribution		(300	)		-
Decrease (Increase) in operating assets-
Receivables		(155	)		226
Materials and supplies		15			(52	)
Prepayments and other current assets		(74	)		(93	)
Increase (Decrease) in operating liabilities-
Accounts payable		(108	)		(114	)
Accrued taxes		73			9
Accrued interest		86			100
Electric service prepayment programs		(17	)		(14	)
Other		(33	)		(32	)
Net cash provided from (used for) operating activities		(75	)		324

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		250			-
Short-term borrowings, net		1,139			200
Redemptions and Repayments-
Common stock		(891	)		-
Preferred stock		-			(30	)
Long-term debt		(13	)		(64	)
Net controlled disbursement activity		12			(8	)
Stock-based compensation tax benefit		8			-
Common stock dividend payments		(159	)		(148	)
Net cash provided from (used for) financing activities		346			(50	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(296	)		(447	)
Proceeds from asset sales		-			57
Proceeds from nuclear decommissioning trust fund sales		266			481
Investments in nuclear decommissioning trust funds		(269	)		(484	)
Cash investments		25			103
Other		2			(20	)
Net cash used for investing activities		(272	)		(310	)

Net decrease in cash and cash equivalents		(1	)		(36	)
Cash and cash equivalents at beginning of period		90			64
Cash and cash equivalents at end of period	$	89		$	28


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 First Quarter~~

~~Basic Earnings Per Share - First Quarter 2006~~		~~$ 0.67~~
~~Revenues~~		~~0.51~~
~~Fuel and purchased power~~		~~(0.24)~~
~~Depreciation and amortization~~		~~(0.08)~~
~~Deferral of new regulatory assets~~		~~0.07~~
~~Other expenses~~		~~(0.05)~~
~~Saxton decommissioning regulatory asset~~		~~0.05~~
~~Trust securities impairment~~		~~(0.01)~~
~~Basic Earnings Per Share - First Quarter 2007~~		~~$ 0.92~~

	Three Months Ended
	March 31,						Increase
	2007			2006			(Decrease)
Net Income	*(In millions, except per share data)*
By Business Segment
Energy delivery services	$	218		$	189		$	29
Competitive energy services		98			32			66
Ohio transitional generation services		24			30			(6	)
Other and reconciling adjustments*		(50	)		(30	)		(20	)
Total	$	290		$	221		$	69

Basic and Diluted Earnings Per Share	$	0.92		$	0.67		$	0.25

~~Electric Distribution Deliveries~~
~~Residential~~	~~7.1~~	%
~~Commercial~~	~~4.3~~	%
~~Industrial~~	~~0.1~~	%
~~Total Distribution Deliveries~~	~~3.9~~	%

Sources of Change in Generation Sales	Increase
	*(In millions)*
Retail:
Effect of 0.3% increase in volume	$	2
Change in prices		81
		83
Wholesale:
Effect of 139% increase in volume		77
Change in prices		-
		77
Net Increase in Generation Sales	$	160