THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Six Months Ended
June 30,
Restated
2008 2007
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 124,424 $ 132,498
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 36,820 37,181
Amortization of regulatory assets 76,781 68,176
Deferral of new regulatory assets (55,267 ) (77,016 )
Deferred rents and lease market valuation liability - (45,858 )
Deferred income taxes and investment tax credits, net (12,125 ) (7,103 )
Accrued compensation and retirement benefits (4,027 ) 1,594
Pension trust contribution - (24,800 )
Decrease (increase) in operating assets-
Receivables 73,484 156,526
Prepayments and other current assets (689 ) 163
Increase (decrease) in operating liabilities-
Accounts payable 11,076 (308,551 )
Accrued taxes (38,654 ) (40,119 )
Accrued interest 178 3,117
Electric service prepayment programs (11,498 ) (11,129 )
Other 2,291 689
Net cash provided from (used for) operating activities 202,794 (114,632 )

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt - 247,426
Redemptions and Repayments-
Long-term debt (335 ) (103,397 )
Short-term borrowings, net (100,562 ) (52,894 )
Dividend Payments-
Common stock (100,000 ) (104,000 )
Net cash used for financing activities (200,897 ) (12,865 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (67,206 ) (64,366 )
Loan repayments from associated companies, net 30,132 2,292
Collection of principal on long-term notes receivable - 133,341
Redemption of lessor notes 37,712 56,175
Other (2,528 ) 70
Net cash provided from (used for) investing activities (1,890 ) 127,512

Net increase in cash and cash equivalents 7 15
Cash and cash equivalents at beginning of period 232 221
Cash and cash equivalents at end of period $ 239 $ 236

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

	Three Months Ended
	March 31				Increase
Revenues by Type of Service	2009		2008		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	91	$	160	$	(69	)
Wholesale		189		129		60
Total Non-Affiliated Generation Sales		280		289		(9	)
Affiliated Generation Sales		893		776		117
Transmission		25		33		(8	)
Lease Revenue		25		-		25
Other		5		7		(2	)
Total Revenues	$	1,228	$	1,105	$	123

The lower retail revenues reflect reduced commercial and industrial contract renewals in the PJM market and the termination of certain government aggregation programs in Ohio. Higher non-affiliated wholesale revenues resulted from higher PJM capacity prices and increased sales volumes in the MISO market, partially offset by lower unit prices and volumes in PJM.

The increased affiliated company generation revenues were due to higher unit prices for sales to the Ohio Companies under their CBP, partially offset by lower unit prices to the Pennsylvania Companies and an overall decrease in affiliated sales volumes. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the composite price to decline. FES supplied less power to the Ohio Companies in the first quarter of 2009 as one of four winning bidders in the Ohio Companies’ RFP process. The amount of power FES will supply to the Ohio Companies for periods beginning on or after June 1, 2009 will be determined by the extent to which FES is successful in bidding in the upcoming CBP, which is currently scheduled to begin on May 13, 2009.

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 57.0% decrease in sales volumes	$	(91	)
Change in prices		22
		(69	)
Wholesale:
Effect of 33.9% increase in sales volumes		44
Change in prices		16
		60
Net Decrease in Non-Affiliated Generation Revenues	$	(9	)

Source of Change in Affiliated Generation Revenues	Increase (Decrease)
	(In millions)
Ohio Companies:
Effect of 24.6% decrease in sales volumes	$	(142	)
Change in prices		246
		104
Pennsylvania Companies:
Effect of 11.1% increase in sales volumes		22
Change in prices		(9	)
		13
Net Increase in Affiliated Generation Revenues	$	117

~~Report~~Transmission revenues decreased $8 million due to decreased retail load in the MISO market ($14 million) partially offset by higher PJM congestion revenue ($6 million). Increased lease revenue represents NGC’s acquisition of ~~Independent Registered Public Accounting Firm~~the equity interests in the OE and TE Beaver Valley and Perry sale and leaseback transactions.

Expenses -

ToTotal expenses decreased $4 million in the ~~Stockholder and Board~~first three months 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 June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 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~~ 2009 due 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 stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, except as to the error correction described in Note 1, which is as of November 24, 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.

~~As discussed in Note 1 to the consolidated financial statements, the Company has restated its 2008 financial statements to correct an error.~~following factors:


~~PricewaterhouseCoopers LLP~~ ~~Cleveland, Ohio~~ ~~August 7, 2008, except as~~·	Purchased power costs decreased $46 million due primarily to ~~the error correction described in Note 1,~~ ~~which is as of November 24, 2008.~~ lower unit costs ($15 million) and reduced volume requirements ($31 million).

·	Fossil fuel costs decreased $15 million due to decreased generation volumes ($53 million) partially offset by higher unit prices ($38 million). The increased unit prices primarily reflect increased fuel rates on existing coal contracts in the first quarter of 2009.

·	Fossil operating costs decreased $4 million due to a $6 million decrease in contractor costs as a result of reduced maintenance activities, partially offset by organizational restructuring costs of $2 million.

·	Other operating expenses increased $27 million due primarily to increased intersegment billings for leasehold costs from the Ohio Companies.

·	Nuclear operating costs increased $16 million due to higher expenses associated with the 2009 Perry refueling outage than incurred with the 2008 Davis-Besse refueling outage.

Higher depreciation expense of $11 million was due to property additions since the first quarter of 2008.

·	Transmission expense increased $7 million due to increased PJM charges.

Other Expense –

Total other expense in the first three months of 2009 was $14 million higher than the first quarter of 2008, primarily due to a $23 million decrease in earnings from nuclear decommissioning trust investments reflecting impairments in the value of securities. This impact was partially offset by a decline in interest expense (net of capitalized interest) of $9 million.

Ohio Transitional Generation Services – First Quarter 2009 Compared with First Quarter 2008

Net income for this segment increased to $24 million in the first three months of 2009 from $23 million in the same period of 2008. Higher operating revenues were almost entirely offset by higher operating expenses, primarily for purchased power.

Revenues –

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

	Three Months Ended
	March 31
Revenues by Type of Service	2009		2008		Increase (Decrease)
	(In millions)
Generation sales:
Retail	$	801	$	606	$	195
Wholesale		-		3		(3	)
Total generation sales		801		609		192
Transmission		110		93		17
Other		1		5		(4	)
Total Revenues	$	912	$	707	$	205

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 5.0% increase in sales volumes	$	30
Change in prices		165
Total Increase in Retail Generation Revenues	$	195

The increase in generation sales was primarily due to reduced customer shopping as most of the Ohio Companies’ customers returned to PLR service in December 2008 due to the termination of certain government aggregation programs in Ohio. Average prices increased primarily due to an increase in the Ohio Companies’ fuel cost recovery rider that became effective in January 2009.

Increased transmission revenue of $17 million resulted from higher sales volumes and a PUCO-approved transmission tariff increase that was effective in mid-2008. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.

Expenses -

Purchased power costs were $310 million higher due primarily to higher unit costs and volumes. The factors contributing to the higher costs are summarized in the following table:

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
2008 2007 2008 2007
(In thousands)

REVENUES:
Electric sales $ 214,353 $ 233,637 $ 418,022 $ 466,693
Excise tax collections 7,153 6,700 15,178 14,100
Total revenues 221,506 240,337 433,200 480,793

EXPENSES:
Purchased power 102,850 96,276 204,148 192,445
Other operating costs 50,805 74,471 96,134 145,260
Provision for depreciation 7,941 9,127 16,966 18,244
Amortization of regulatory assets 25,360 24,948 50,385 48,824
Deferral of new regulatory assets (8,929 ) (18,247 ) (18,423 ) (31,728 )
General taxes 12,605 13,000 26,982 26,734
Total expenses 190,632 199,575 376,192 399,779

OPERATING INCOME 30,874 40,762 57,008 81,014

OTHER INCOME (EXPENSE):
Investment income 5,224 7,309 11,705 14,534
Miscellaneous expense (1,949 ) (2,056 ) (3,463 ) (5,156 )
Interest expense (5,578 ) (8,916 ) (11,613 ) (16,419 )
Capitalized interest 88 164 125 247
Total other expense (2,215 ) (3,499 ) (3,246 ) (6,794 )

INCOME BEFORE INCOME TAXES 28,659 37,263 53,762 74,220

INCOME TAXES 7,352 15,392 15,440 26,489

NET INCOME 21,307 21,871 38,322 47,731

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (64 ) 573 (127 ) 1,146
Change in unrealized gain on available-for-sale-securities (2,481 ) (669 ) (520 ) (290 )
Other comprehensive income (loss) (2,545 ) (96 ) (647 ) 856
Income tax expense (benefit) related to other
comprehensive income (914 ) (43 ) (186 ) 291
Other comprehensive income (loss), net of tax (1,631 ) (53 ) (461 ) 565

TOTAL COMPREHENSIVE INCOME $ 19,676 $ 21,818 $ 37,861 $ 48,296

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

Source of Change in Purchased Power	Increase
	(In millions)
Purchases:
Change due to increased unit costs	$	284
Change due to increased volumes		26
	$	310

The increase in purchased volumes was due to the higher retail generation sales requirements described above. The higher unit costs reflect the implementation of the Ohio Companies’ CBP for their power supply for retail customers.

Other operating expenses decreased $59 million due to lower MISO transmission-related expenses and increased intersegment credits related to the Ohio Companies’ generation leasehold interests. The deferral of regulatory assets increased by $45 million due to CEI’s deferral of purchased power costs as approved by the PUCO, partially offset by reduced MISO transmission cost deferrals. The difference between transmission revenues accrued and transmission expenses incurred is deferred or amortized, resulting in no material impact to current period earnings.

Other – First Quarter 2009 Compared with First Quarter 2008

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 $10 million decrease in FirstEnergy’s net income in the first three months of 2009 compared to the same period in 2008. The decrease resulted primarily from the absence of the gain on the 2008 sale of telecommunication assets ($19 million, net of taxes), partially offset by the favorable resolution in 2009 of income tax issues relating to prior years ($13 million).

CAPITAL RESOURCES AND LIQUIDITY

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

THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2008 2007
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 22 $ 22
Receivables-
Customers 1,251 449
Associated companies 13,465 88,796
Other (less accumulated provisions of $174,000 and $615,000,
respectively, for uncollectible accounts) 9,901 3,116
Notes receivable from associated companies 56,912 154,380
Prepayments and other 1,157 865
82,708 247,628
UTILITY PLANT:
In service 852,806 931,263
Less - Accumulated provision for depreciation 397,496 420,445
455,310 510,818
Construction work in progress 6,111 19,740
461,421 530,558
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes 142,687 154,646
Long-term notes receivable from associated companies 37,384 37,530
Nuclear plant decommissioning trusts 68,002 66,759
Other 1,712 1,756
249,785 260,691
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 500,576 500,576
Regulatory assets 171,030 203,719
Pension assets 30,240 28,601
Property taxes 21,010 21,010
Other 62,686 20,496
785,542 774,402
$ 1,579,456 $ 1,813,279
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 34 $ 34
Accounts payable-
Associated companies 44,205 245,215
Other 4,339 4,449
Notes payable to associated companies 34,954 13,396
Accrued taxes 22,322 30,245
Lease market valuation liability 36,900 36,900
Other 15,256 22,747
158,010 352,986
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 173,170 173,169
Accumulated other comprehensive loss (11,067 ) (10,606 )
Retained earnings 213,940 175,618
Total common stockholder's equity 523,053 485,191
Long-term debt and other long-term obligations 303,386 303,397
826,439 788,588
NONCURRENT LIABILITIES:
Accumulated deferred income taxes 100,308 103,463
Accumulated deferred investment tax credits 9,753 10,180
Lease market valuation liability 291,550 310,000
Retirement benefits 65,291 63,215
Asset retirement obligations 29,225 28,366
Deferred revenues - electric service programs 6,622 12,639
Lease assignment payable to associated companies 28,835 83,485
Other 63,423 60,357
595,007 671,705
COMMITMENTS AND CONTINGENCIES (Note 10)
$ 1,579,456 $ 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.
As of March 31, 2009, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($2.4 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debt as of March 31, 2009, included the following (in millions):

Currently Payable Long-term Debt
PCRBs supported by bank LOCs(1)	$	1,636
FGCO and NGC unsecured PCRBs(1)		82
Penelec unsecured notes(2)		100
CEI secured notes(3)		150
Met-Ed secured notes(4)		100
NGC collateralized lease obligation bonds		36
Sinking fund requirements		40
	$	2,144

(1) Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity. (2) Matured in April 2009. (3) Mature in November 2009. (4) Mature in March 2010.

Short-Term Borrowings

FirstEnergy had approximately $2.4 billion of short-term borrowings as of March 31, 2009, and December 31, 2008. FirstEnergy, along with certain of its subsidiaries, have access to $2.75 billion of short-term financing under a revolving credit facility that expires in August 2012. A total of 25 banks participate in the facility, with no one bank having more than 7.3% of the total commitment. As of May 1, 2009, FirstEnergy had $720 million of bank credit facilities in addition to the $2.75 billion revolving credit facility. Also, an aggregate of $550 million of accounts receivable financing facilities through the Ohio and Pennsylvania Companies may be accessed to meet working capital requirements and for other general corporate purposes. FirstEnergy’s available liquidity as of May 1, 2009, is summarized in the following table:

Company	Type	Maturity	Commitment		Available Liquidity as of May 1, 2009
			(In millions)
FirstEnergy(1)	Revolving	Aug. 2012	$	2,750	$	227
FirstEnergy and FES	Revolving	May 2009		300		300
FirstEnergy	Bank lines	Various(2)		120		20
FGCO	Term loan	Oct. 2009(3)		300		300
Ohio and Pennsylvania Companies	Receivables financing	Various(4)		550		416
		Subtotal	$	4,020	$	1,263
		Cash		-		698
		Total	$	4,020	$	1,961
(1) FirstEnergy Corp. and subsidiary borrowers. (2) $100 million matures March 31, 2011; $20 million uncommitted line of credit has no maturity date. (3) Drawn amounts are payable within 30 days and may not be re-borrowed. (4) $180 million expires December 18, 2009, $370 million expires February 22, 2010.

Revolving Credit Facility

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

The 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 as of March 31, 2009:

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Six Months Ended
June 30,
Restated
2008 2007
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 38,322 $ 47,731
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 16,966 18,244
Amortization of regulatory assets 50,385 48,824
Deferral of new regulatory assets (18,423 ) (31,728 )
Deferred rents and lease market valuation liability (39,045 ) (41,981 )
Deferred income taxes and investment tax credits, net (3,113 ) (11,924 )
Accrued compensation and retirement benefits (1,160 ) 1,277
Pension trust contribution - (7,659 )
Decrease (increase) in operating assets-
Receivables 76,978 (21,594 )
Prepayments and other current assets (292 ) 59
Increase (decrease) in operating liabilities-
Accounts payable (166,120 ) (56,784 )
Accrued taxes (7,923 ) 751
Electric service prepayment programs (6,017 ) (5,334 )
Other 870 2,569
Net cash used for operating activities (58,572 ) (57,549 )

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net 21,558 88,686
Redemptions and Repayments-
Long-term debt (17 ) -
Dividend Payments-
Common stock (35,000 ) (40,000 )
Net cash provided from (used for) financing activities (13,459 ) 48,686

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (34,388 ) (19,804 )
Loan repayments from (loans to) associated companies, net 97,479 (19,546 )
Collection of principal on long-term notes receivable 135 32,327
Redemption of lessor notes 11,959 14,846
Sales of investment securities held in trusts 21,791 32,499
Purchases of investment securities held in trusts (23,581 ) (34,271 )
Other (1,364 ) 2,812
Net cash provided from investing activities 72,031 8,863

Net change in cash and cash equivalents - -
Cash and cash equivalents at beginning of period 22 22
Cash and cash equivalents at end of period $ 22 $ 22

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

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

(1)No regulatory approvals, statutory or charter limitations applicable. (2)Excluding amounts which may be borrowed under the regulated companies’ money pool. (3)Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s. (4)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.

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, 2009, FirstEnergy’s and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy(1)	60.8	%
FES	57.3	%
OE	44.8	%
Penn	19.5	%
CEI	54.4	%
TE	44.6	%
JCP&L	36.3	%
Met-Ed	50.0	%
Penelec	52.0	%

(1)As of March 31, 2009, FirstEnergy could issue additional debt of approximately

$3.0 billion, or recognize a reduction in equity of approximately $1.6 billion, and

remain within the limitations of the financial covenants required by its revolving

credit facility.

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 Money Pools

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 2009 was 0.97% for the regulated companies’ money pool and 1.01% for the unregulated companies’ money pool.

~~Report of Independent Registered Public Accounting Firm~~Pollution Control Revenue Bonds

As of March 31, 2009, FirstEnergy’s currently payable long-term debt includes approximately $1.6 billion (FES - $1.6 billion, Met-Ed - $29 million and Penelec - $45 million) of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or; if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.

The LOCs for FirstEnergy variable interest rate PCRBs were issued by the following banks:

	Aggregate LOC			Reimbursements of
LOC Bank	Amount(4)		LOC Termination Date	LOC Draws Due
	(In millions)
Barclays Bank	$	149	June 2009	June 2009
Bank of America(1)	101		June 2009	June 2009
The Bank of Nova Scotia	255		Beginning June 2010	Shorter of 6 months or LOC termination date
The Royal Bank of Scotland	131		June 2012	6 months
KeyBank(2)	266		June 2010	6 months
Wachovia Bank	153		March 2014	March 2014
Barclays Bank(3)	528		Beginning December 2010	30 days
PNC Bank	70		Beginning December 2010	180 days
Total	$	1,653

(1) Supported by two participating banks, with each having 50% of the total commitment. (2) Supported by four participating banks, with the LOC bank having 62% of the total commitment. (3) Supported by 18 participating banks, with no one bank having more than 14% of the total commitment. (4) Includes approximately $16 million of applicable interest coverage.

In February 2009, holders of approximately $434 million principal of LOC-supported PCRBs of OE and NGC were notified that the applicable Wachovia Bank LOCs were to expire on March 18, 2009. As a result, these PCRBs were subject to mandatory purchase at a price equal to the principal amount, plus accrued and unpaid interest, which OE and NGC funded through short-term borrowings. In March 2009, FGCO remarketed $100 million of those PCRBs, which were previously held by OE. In addition, approximately $250 million of FirstEnergy’s PCRBs that are currently supported by LOCs are expected to be remarketed or refinanced in fixed interest rate modes and secured by FMBs, thereby eliminating or reducing the need for third-party credit support.

~~To the Stockholder and Board of~~

~~Directors of Pennsylvania Electric Company:~~Long-Term Debt Capacity

~~We have reviewed~~As of March 31, 2009, the ~~accompanying consolidated balance sheet~~Ohio Companies and Penn had the aggregate capability to issue approximately $2.7 billion of ~~Pennsylvania Electric Company~~additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. As a result of the issuance of senior secured notes by TE referred to below and related amendments to the TE mortgage indenture’s bonding ratio, that capacity decreased to $2.3 billion. The issuance of FMBs by the Ohio Companies is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding 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 $171 million, $164 million and $117 million, respectively, as of March 31, 2009. In April 2009, TE issued $300 million of new senior secured notes backed by FMBs. Concurrently with that issuance and in order to satisfy the limitation on secured debt under its senior note indenture, TE issued an additional $300 million of FMBs to secure $300 million of its outstanding unsecured senior notes originally issued in November 2006. Based upon FGCO’s FMB indenture, net earnings and available bondable property additions as of March 31, 2009, FGCO had the capability to issue $2.7 billion of additional FMBs under the terms of that indenture. Met-Ed and Penelec had the capability to issue secured debt of approximately $423 million and $321 million, respectively, under provisions of their senior note indentures as of March 31, 2009.

FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. On March 2, 2009, Moody’s assigned a Baa1 senior secured rating to FES-related secured issuances. The following table displays FirstEnergy’s, FES’ and the Utilities’ securities ratings as of April 30, 2009. S&P’s and Moody’s outlook for FirstEnergy and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

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.

~~As discussed in Note 1 to the consolidated financial statements, the Company has restated its 2008 financial statements to correct an error.~~

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~August 7, 2008, except as to the error correction described in Note 1,~~

~~which is as of November 24, 2008.~~

remains “stable.”

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
2008 2007 2008 2007
(In thousands)
REVENUES:
Electric sales $ 335,382 $ 315,745 $ 711,410 $ 654,971
Gross receipts tax collections 16,040 15,672 35,504 32,352
Total revenues 351,422 331,417 746,914 687,323

EXPENSES:
Purchased power 205,791 184,494 427,025 385,336
Other operating costs 50,100 58,267 121,177 117,728
Provision for depreciation 13,918 12,335 26,434 24,112
Amortization of regulatory assets, net 19,111 13,481 31,931 11,787
General taxes 18,345 18,350 40,200 38,201
Total expenses 307,265 286,927 646,767 577,164

OPERATING INCOME 44,157 44,490 100,147 110,159

OTHER INCOME (EXPENSE):
Miscellaneous income 1,058 2,135 867 3,552
Interest expense (14,901 ) (13,072 ) (30,223 ) (24,409 )
Capitalized interest 70 285 (736 ) 543
Total other expense (13,773 ) (10,652 ) (30,092 ) (20,314 )

INCOME BEFORE INCOME TAXES 30,384 33,838 70,055 89,845

INCOME TAXES 11,987 14,375 30,266 38,638

NET INCOME 18,397 19,463 39,789 51,207

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (3,474 ) (2,825 ) (6,947 ) (5,650 )
Unrealized gain on derivative hedges 16 17 32 33
Change in unrealized gain on available-for-sale securities (21 ) (13 ) (10 ) (16 )
Other comprehensive loss (3,479 ) (2,821 ) (6,925 ) (5,633 )
Income tax benefit related to other comprehensive loss (1,520 ) (1,302 ) (3,026 ) (2,600 )
Other comprehensive loss, net of tax (1,959 ) (1,519 ) (3,899 ) (3,033 )

TOTAL COMPREHENSIVE INCOME $ 16,438 $ 17,944 $ 35,890 $ 48,174

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

Issuer	Securities	S&P	Moody’s

FirstEnergy	Senior unsecured	BBB-	Baa3

FES	Senior secured	BBB	Baa1
	Senior unsecured	BBB	Baa2

OE	Senior secured	BBB+	Baa1
	Senior unsecured	BBB	Baa2

Penn	Senior secured	A-	Baa1

CEI	Senior secured	BBB+	Baa2
	Senior unsecured	BBB	Baa3

TE	Senior secured	BBB+	Baa2
	Senior unsecured	BBB	Baa3

JCP&L	Senior unsecured	BBB	Baa2

Met-Ed	Senior unsecured	BBB	Baa2

Penelec	Senior unsecured	BBB	Baa2

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

Changes in Cash Position

As of March 31, 2009, FirstEnergy had $399 million in cash and cash equivalents compared to $545 million as of December 31, 2008. Cash and cash equivalents consist of unrestricted, highly liquid instruments with an original or remaining maturity of three months or less. As of March 31, 2009, approximately $311 million of cash and cash equivalents represented temporary overnight deposits.

During the first quarter of 2009, FirstEnergy received $248 million of cash from dividends and equity repurchases 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 FirstEnergy’s subsidiaries. In addition to paying dividends from retained earnings, each of FirstEnergy’s electric utility subsidiaries has authorization from the FERC to pay cash dividends from paid-in capital accounts, as long as the subsidiary’s debt to total capitalization ratio (without consideration of retained earnings) remains below 65%.

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 $462 million in the first three months of 2009 compared to $359 million in the first three months of 2008, as summarized in the following table:

	Three Months Ended
	March 31,
Operating Cash Flows	2009			2008
	(In millions)
Net income	$	115		$	277
Non-cash charges		375			211
Working capital and other		(28	)		(129	)
	$	462		$	359

Net cash provided from operating activities increased by $103 million in the first three months of 2009 compared to the first three months of 2008 primarily due to a $164 million increase in non-cash charges and a $101 million increase from working capital and other changes, partially offset by a $162 million decrease in net income (see Results of Operations above). The increase in non-cash charges is primarily due to higher amortization of regulatory assets, including CEI’s $216 million regulatory asset impairment, and changes in accrued compensation and retirement benefits. The change in accrued compensation and retirement benefits resulted primarily from higher non-cash retirement benefit expenses recognized in the first quarter of 2009. The changes in working capital and other primarily resulted from a $52 million increase in the collection of receivables, lower net tax payments of $20 million and an increase in other accrued expenses principally associated with the implementation of the Ohio Companies’ Amended ESP.

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2008 2007
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 38 $ 46
Receivables-
Customers (less accumulated provisions of $3,197,000 and $3,905,000
respectively, for uncollectible accounts) 137,431 137,455
Associated companies 12,309 22,014
Other 31,998 19,529
Notes receivable from associated companies 16,464 16,313
Prepaid gross receipts taxes 25,202 -
Other 11,245 3,077
234,687 198,434
UTILITY PLANT:
In service 2,267,105 2,219,002
Less - Accumulated provision for depreciation 852,428 838,621
1,414,677 1,380,381
Construction work in progress 22,457 24,251
1,437,134 1,404,632
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts 132,904 137,859
Non-utility generation trusts 115,152 112,670
Other 303 531
248,359 251,060
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 777,616 777,904
Pension assets 72,698 66,111
Other 29,333 33,893
879,647 877,908
$ 2,799,827 $ 2,732,034
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 145,000 $ -
Short-term borrowings-
Associated companies 211,773 214,893
Other 100,000 -
Accounts payable-
Associated companies 24,434 83,359
Other 45,418 51,777
Accrued taxes 12,393 15,111
Accrued interest 13,167 13,167
Other 25,515 25,311
577,700 403,618
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 920,293 920,616
Accumulated other comprehensive income 1,047 4,946
Retained earnings 97,732 57,943
Total common stockholder's equity 1,107,624 1,072,057
Long-term debt and other long-term obligations 632,687 777,243
1,740,311 1,849,300
NONCURRENT LIABILITIES:
Regulatory liabilities 79,304 73,559
Asset retirement obligations 84,428 81,849
Accumulated deferred income taxes 214,642 210,776
Retirement benefits 41,186 41,298
Other 62,256 71,634
481,816 479,116
COMMITMENTS AND CONTINGENCIES (Note 10)
$ 2,799,827 $ 2,732,034

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

Cash Flows From Financing Activities

In the first three months of 2009, cash provided from financing activities was $70 million compared to $224 million in the first three months of 2008. The decrease was primarily due to lower short-term borrowings, partially offset by long-term debt issuances in the first quarter of 2009. The following table summarizes security issuances and redemptions.

	Three Months Ended
	March 31
Securities Issued or Redeemed	2009		2008
	(In millions)
New issues
Pollution control notes	$	100	$	-
Unsecured notes		600		-
	$	700	$	-

Redemptions
Pollution control notes(1)	$	437	$	362
Senior secured notes		7		6
	$	444	$	368

Short-term borrowings, net	$	-	$	746

(1) Includes the mandatory purchase of certain auction rate PCRBs described above.

On January 20, 2009, Met-Ed issued $300 million of 7.70% Senior Notes due 2019 and used the net proceeds to repay short-term borrowings. On January 27, 2009, JCP&L issued $300 million of 7.35% Senior Notes due 2019 and used the net proceeds to repay short-term borrowings, to fund capital expenditures and for other general corporate purposes. On April 24, 2009, TE issued $300 million of 7.25% Senior Secured Notes due 2020 and used the net proceeds to repay short-term borrowings, to fund capital expenditures and for other general corporate purposes. Each of these issuances was sold off the shelf registration referenced above.

Cash Flows From Investing Activities

Net cash flows used in investing activities resulted principally from property additions. Additions for the energy delivery services segment primarily include expenditures related to transmission and distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for the three months ended March 31, 2009, and 2008 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, 2009
Energy delivery services	$	(165	)	$	51		$	(14	)	$	(128	)
Competitive energy services		(421	)		2			(19	)		(438	)
Other		(49	)		(20	)		1			(68	)
Inter-segment reconciling items		(19	)		(25	)		-			(44	)
Total	$	(654	)		8			(32	)		(678	)

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	)

Net cash used for investing activities in the first quarter of 2009 increased by $36 million compared to the first quarter of 2008. The increase was primarily due to the absence in 2009 of cash proceeds from the sale of telecommunication assets in the first quarter of 2008 and higher cash investments for the Signal Peak mining operations in 2009, partially offset by lower property additions. Property additions decreased as a result of lower AQC system expenditures in the first quarter of 2009 and the absence in 2009 of acquisition costs for the Fremont Plant in the first quarter of 2008.

During the remaining three quarters of 2009, capital requirements for property additions and capital leases are expected to be approximately $1.4 billion, including approximately $225 million for nuclear fuel. FirstEnergy has additional requirements of approximately $316 million for maturing long-term debt during the remainder of 2009, of which $100 million was redeemed in April 2009. 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 2009-2013 is expected to be approximately $8.1 billion (excluding nuclear fuel), of which approximately $1.6 billion applies to 2009. Investments for additional nuclear fuel during the 2009-2013 period are estimated to be approximately $1.3 billion, of which about $338 million applies to 2009. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $1.0 billion and $136 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, 2009, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.5 billion, as summarized below:

	Maximum
Guarantees and Other Assurances	Exposure
	(In millions)
FirstEnergy Guarantees on Behalf of its Subsidiaries
Energy and Energy-Related Contracts (1)	$	433
LOC (long-term debt) – interest coverage (2)		6
Other (3)		742
		1,181

Subsidiaries’ Guarantees
Energy and Energy-Related Contracts		77
LOC (long-term debt) – interest coverage (2)		9
FES’ guarantee of FGCO’s sale and leaseback obligations		2,552
		2,638

Surety Bonds		111
LOC (long-term debt) – interest coverage (2)		2
LOC (non-debt) (4)(5)		570
		683
Total Guarantees and Other Assurances	$	4,502

(1)

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

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Six Months Ended
June 30,
Restated
2008 2007
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 39,789 $ 51,207
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 26,434 24,112
Amortization of regulatory assets, net 31,931 11,787
Deferred costs recoverable as regulatory assets (13,288 ) (34,691 )
Deferred income taxes and investment tax credits, net 12,760 13,548
Accrued compensation and retirement benefits (16,293 ) (12,130 )
Cash collateral 301 3,250
Pension trust contribution - (13,436 )
Increase in operating assets-
Receivables (11,082 ) (39,530 )
Prepayments and other current assets (33,370 ) (20,819 )
Increase (decrease) in operating liabilities-
Accounts payable (9,438 ) (70,070 )
Accrued taxes (11,804 ) (8,750 )
Accrued interest - 181
Other 9,714 5,447
Net cash provided from (used for) operating activities 25,654 (89,894 )

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 45,000 -
Short-term borrowings, net 96,880 166,303
Redemptions and Repayments-
Long-term debt (45,320 ) -
Dividend Payments-
Common stock (55,000 ) (25,000 )
Net cash provided from financing activities 41,560 141,303

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (57,314 ) (43,904 )
Loan repayments from (loans to) associated companies, net (151 ) 1,285
Sales of investment securities held in trust 45,108 26,882
Purchases of investment securities held in trust (53,537 ) (33,680 )
Other (1,328 ) (1,996 )
Net cash used for investing activities (67,222 ) (51,413 )

Net decrease in cash and cash equivalents (8 ) (4 )
Cash and cash equivalents at beginning of period 46 44
Cash and cash equivalents at end of period $ 38 $ 40

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

(2)

Reflects the interest coverage portion of LOCs issued in support of floating rate PCRBs with various maturities. The principal amount of floating-rate PCRBs of $1.6 billion is reflected in currently payable long-term debt on FirstEnergy’s consolidated balance sheets.

(3)

Includes guarantees of $300 million for OVEC obligations and $80 million for nuclear decommissioning funding assurances. Also includes $300 million for a Credit Suisse credit facility for FGCO that is guaranteed by both FirstEnergy and FES.

(4)

Includes $145 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility.

(5)

Includes approximately $291 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE. A $236 million LOC relating to the sale-leaseback of Beaver Valley Unit 2 by OE expires in May 2009 and is expected to be replaced by a $161 million LOC.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~1. ORGANIZATION AND BASIS OF PRESENTATION~~FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge 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 its 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 FirstEnergy assets. FirstEnergy believes 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 to below investment grade or a “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of March 31, 2009, FirstEnergy’s maximum exposure under these collateral provisions was $761 million as shown below:

Collateral Provisions	FES		Utilities		Total
	(In millions)
Credit rating downgrade to below investment grade	$	315	$	170	$	485
Acceleration of payment or funding obligation		80		141		221
Material adverse event		50		5		55
Total	$	445	$	316	$	761

Stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase the total potential amount to $830 million, consisting of $54 million due to “material adverse event” contractual clauses and $776 million due to a below investment grade credit rating.

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.

In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ power portfolio as of March 31, 2009, and forward prices as of that date, FES had $205 million of outstanding collateral payments. Under a hypothetical adverse change in forward prices (15% decrease in the first 12 months and 20% decrease thereafter in prices), FES would be required to post an additional $77 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post significantly higher amounts for margining.

OFF-BALANCE SHEET ARRANGEMENTS

FES and the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to sale and leaseback arrangements involving the Bruce Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments is $1.7 billion as of March 31, 2009.

FirstEnergy ishas 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 ~~diversified energy company that holds, directly~~material current or ~~indirectly, all of the outstanding common stock of~~future effect on its ~~principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and its subsidiaries FGCO and NGC, and FESC.~~

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

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2007 for FirstEnergy, FES and the Companies. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.MARKET RISK INFORMATION

FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and ~~its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities~~interest rate fluctuations. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general oversight for ~~which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 8) when it is determined to be~~risk management activities throughout the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.

The consolidated financial statements as of June 30, 2008 and for the three-month and six-month periods ended June 30, 2008 and 2007, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated August 7, 2008, except as to the error correction described in Note 1, which is as of November 24, 2008) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.

~~Restatement of the Consolidated Statements of Cash Flows~~

OE, CEI, TE and Penelec are restating their respective Consolidated Statements of Cash Flows for the six months ended June 30, 2008, to correct common stock dividend payments reported in cash flows from financing activities. The consolidated statements of cash flows for those registrants, as originally filed, erroneously did not reflect the payment of common stock dividends in the first and second quarters of 2008, which were declared in the third quarter of 2007. The corrections resulted in a corresponding change in operating liabilities - accounts payable, included in cash flows from operating activities.

This correction does not affect the respective registrants’ previously reported consolidated statements of income and comprehensive income for the three months and six months ended June 30, 2008 and consolidated balance sheets as of June 30, 2008 contained in the combined Form 10-Q for the quarter ended June 30, 2008, as originally filed on August 7, 2008.

~~The effects of the corrections on OE’s, CEI’s, TE’s and Penelec’s Consolidated Statements of Cash Flows for the six months ended June 30, 2008 are as follows:~~company.

OE

Six Months
Ended June 30, 2008
As Previously As
Reported Restated
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 92,751 $ 92,751
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 42,907 42,907
Amortization of regulatory assets 96,394 96,394
Deferral of new regulatory assets (51,312 ) (51,312 )
Amortization of lease costs (4,399 ) (4,399 )
Deferred income taxes and investment tax credits, net 7,059 7,059
Accrued compensation and retirement benefits (31,579 ) (31,579 )
Decrease (increase) in operating assets-
Receivables 30,159 30,159
Prepayments and other current assets (2,485 ) (2,485 )
Decrease in operating liabilities-
Accounts payable (56,831 ) (6,831 )
Accrued taxes (31,306 ) (31,306 )
Accrued interest (1,252 ) (1,252 )
Electric service prepayment programs

(21,771 ) (21,771 )
Other 2,671 2,671
Net cash provided from operating activities 71,006 121,006

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net 69,573 69,573
Redemptions and Repayments-
Long-term debt (175,577 ) (175,577 )
Dividend Payments-
Common stock - (50,000 )
Net cash used for financing activities (106,004 ) (156,004 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (92,061 ) (92,061 )
Sales of investment securities held in trusts 79,613 79,613
Purchases of investment securities held in trusts (84,130 ) (84,130 )
Loan repayments from associated companies, net 123,905 123,905
Cash investments 5,000 5,000
Other 2,828 2,828
Net cash provided from investing activities 35,155 35,155

Net increase in cash and cash equivalents $ 157 $ 157

CEI

Six Months
Ended June 30, 2008
As Previously As
Reported Restated
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 124,424 $ 124,424
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 36,820 36,820
Amortization of regulatory assets 76,781 76,781
Deferral of new regulatory assets (55,267 ) (55,267 )
Deferred income taxes and investment tax credits, net (12,125 ) (12,125 )
Accrued compensation and retirement benefits (4,027 ) (4,027 )
Decrease (increase) in operating assets-
Receivables 73,484 73,484
Prepayments and other current assets (689 ) (689 )
Increase (decrease) in operating liabilities-
Accounts payable (88,924 ) 11,076
Accrued taxes (38,654 ) (38,654 )
Accrued interest 178 178
Electric service prepayment programs (11,498 ) (11,498 )
Other 2,291 2,291
Net cash provided from operating activities 102,794 202,794

CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt (335 ) (335 )
Short-term borrowings, net (100,562 ) (100,562 )
Dividend Payments-
Common stock - (100,000 )
Net cash used for financing activities (100,897 ) (200,897 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (67,206 ) (67,206 )
Loan repayments from associated companies, net 30,132 30,132
Redemption of lessor notes 37,712 37,712
Other (2,528 ) (2,528 )
Net cash used for investing activities (1,890 ) (1,890 )

Net increase in cash and cash equivalents $ 7 $ 7

TE

Six Months
Ended June 30, 2008
As Previously As
Reported Restated
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 38,322 $ 38,322
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 16,966 16,966
Amortization of regulatory assets 50,385 50,385
Deferral of new regulatory assets (18,423 ) (18,423 )
Deferred rents and lease market valuation liability (39,045 ) (39,045 )
Deferred income taxes and investment tax credits, net (3,113 ) (3,113 )
Accrued compensation and retirement benefits (1,160 ) (1,160 )
Decrease (increase) in operating assets-
Receivables 76,978 76,978
Prepayments and other current assets (292 ) (292 )
Increase (decrease) in operating liabilities-
Accounts payable (201,120 ) (166,120 )
Accrued taxes (7,923 ) (7,923 )
Electric service prepayment programs (6,017 ) (6,017 )
Other 870 870
Net cash used for operating activities (93,572 ) (58,572 )

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net 21,558 21,558
Redemptions and Repayments-
Long-term debt (17 ) (17 )
Dividend Payments-
Common stock - (35,000 )
Net cash provided from (used for) financing activities 21,541 (13,459 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (34,388 ) (34,388 )
Loan repayments from (loans to) associated companies, net 97,479 97,479
Collection of principal on long-term notes receivable 135 135
Redemption of lessor notes 11,959 11,959
Sales of investment securities held in trusts 21,791 21,791
Purchases of investment securities held in trusts (23,581 ) (23,581 )
Other (1,364 ) (1,364 )
Net cash provided from investing activities 72,031 72,031

Net change in cash and cash equivalents $ - $ -

PENELEC

Six Months
Ended June 30, 2008
As Previously As
Reported Restated
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 39,789 $ 39,789
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 26,434 26,434
Amortization of regulatory assets, net 31,931 31,931
Deferred costs recoverable as regulatory assets (13,288 ) (13,288 )
Deferred income taxes and investment tax credits, net 12,760 12,760
Accrued compensation and retirement benefits (16,293 ) (16,293 )
Cash collateral 301 301
Increase in operating assets-
Receivables (11,082 ) (11,082 )
Prepayments and other current assets (33,370 ) (33,370 )
Increase (decrease) in operating liabilities-
Accounts payable (64,438 ) (9,438 )
Accrued taxes (11,804 ) (11,804 )
Other 9,714 9,714
Net cash provided from (used for) operating activities (29,346 ) 25,654

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 45,000 45,000
Short-term borrowings, net 96,880 96,880
Redemptions and Repayments-
Long-term debt (45,320 ) (45,320 )
Dividend Payments-
Common stock - (55,000 )
Net cash provided from financing activities 96,560 41,560

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (57,314 ) (57,314 )
Loan repayments from (loans to) associated companies, net (151 ) (151 )
Sales of investment securities held in trust 45,108 45,108
Purchases of investment securities held in trust (53,537 ) (53,537 )
Other (1,328 ) (1,328 )
Net cash used for investing activities (67,222 ) (67,222 )

Net decrease in cash and cash equivalents $ (8 ) $ (8 )

~~2. EARNINGS PER SHARE~~

Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The pool of stock-based compensation tax benefits is calculated in accordance with SFAS 123(R). On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an accelerated share repurchase program at an initial price of approximately $900 million. A final purchase price adjustment of $51 million was settled in cash on December 13, 2007. The following table reconciles basic and diluted earnings per share of common stock:

Three Months Six Months

Ended June 30

Ended June 30

Reconciliation of Basic and Diluted Earnings per Share 2008 2007 2008 2007
(In millions, except per share amounts)

Net income $ 263 $ 338 $ 539 $ 628

Average shares of common stock outstanding – Basic 304 304 304 309
Assumed exercise of dilutive stock options and awards 3 4 3 4
Average shares of common stock outstanding – Dilutive 307 308 307 313

Basic earnings per share $ 0.86 $ 1.11 $ 1.77 $ 2.03
Diluted earnings per share $ 0.85 $ 1.10 $ 1.75 $ 2.01

~~3. DIVESTITURES AND DISCONTINUED OPERATIONS~~

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

~~4. FAIR VALUE MEASURES~~

Effective January 1, 2008, FirstEnergy adopted SFAS 157, which provides a framework for measuring fair value under GAAP and, among other things, requires enhanced disclosures about assets and liabilities recognized at fair value. FirstEnergy also adopted SFAS 159 on January 1, 2008, which provides the option to measure certain financial assets and financial liabilities at fair value. FirstEnergy has analyzed its financial assets and financial liabilities within the scope of SFAS 159 and, as of June 30, 2008, has elected not to record eligible assets and liabilities at fair value.

As defined in SFAS 157, fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that are held in various trusts.

Level 2 – Pricing inputs are either directly or indirectly observable in the market as of the reporting date, other than quoted prices in active markets included in Level 1. FirstEnergy’s Level 2 consists primarily of investments in debt securities held in various trusts and commodity forwards. Additionally, Level 2 includes those financial instruments that are valued using models or other valuation methodologies based on assumptions that are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Instruments in this category include non-exchange-traded derivatives such as forwards and certain interest rate swaps.

Level 3 – Pricing inputs include inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. FirstEnergy develops its view of the future market price of key commodities through a combination of market observation and assessment (generally for the short term) and fundamental modeling (generally for the longer term). Key fundamental electricity model inputs are generally directly observable in the market or derived from publicly available historic and forecast data. Some key inputs reflect forecasts published by industry leading consultants who generally employ similar fundamental modeling approaches. Fundamental model inputs and results, as well as the selection of consultants, reflect the consensus of appropriate FirstEnergy management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. FirstEnergy’s Level 3 instruments consist of NUG contracts.

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

The following table sets forth FirstEnergy’s financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of June 30, 2008. As required by SFAS 157, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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

Liabilities:
    Derivatives $ - $ 123 $ - $ 123
    NUG contracts(3)
- - 644 644
    Total $ - $ 123 $ 644 $ 767

~~(1)~~

~~Balance excludes $2 million of net receivables, payables and accrued income.~~

~~(2)~~

~~Excludes $312 million of the cash surrender value of life insurance contracts.~~

~~(3)~~

~~NUG contracts are completely offset by regulatory assets.~~

The determination of the above fair value measures takes into consideration various factors required under SFAS 157. These factors include the credit standing of the counterparties involved, the impact of credit enhancements (such as cash deposits, LOCs and priority interests) and the impact of nonperformance risk.

Exchange-traded derivative contracts, which include some futures and options, are generally based on unadjusted quoted market prices in active markets and are classified within Level 1. Forwards, options and swap contracts that are not exchange-traded are classified as Level 2 as the fair values of these items are based on ICE quotes or market transactions in the OTC markets. In addition, complex or longer term structured transactions can introduce the need for internally-developed model inputs that may not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is classified as Level 3.

Nuclear decommissioning trusts consist of equity securities listed on active exchanges classified as Level 1 and various debt securities and collective trusts classified as Level 2. Other investments represent the NUG trusts, spent nuclear fuel trusts and rabbi trust investments, which primarily consist of various debt securities and collective trusts classified as Level 2.

~~The following tables set forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three and six months ended June 30, 2008:~~

Three Months Six Months
Ended June 30, 2008 Ended June 30, 2008
(In millions)
Balance at beginning of period $ 682 $ 750
    Realized and unrealized gains (losses)(1)
(30 ) (88 )
    Purchases, sales, issuances and settlements, net(1)
(8 ) (18 )
    Net transfers to (from) Level 3 - -
Balance as of June 30, 2008 $ 644 $ 644

Change in unrealized gains (losses) relating to
    instruments held as of June 30, 2008 $ (30 ) $ (88 )

(1) Changes in the fair value of NUG contracts are completely offset by regulatory assets and do not impact earnings

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

~~5. DERIVATIVE INSTRUMENTS~~Commodity Price Risk

FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices ~~including prices for~~-- electricity, energy transmission, natural gas, coal, nuclear fuel and ~~energy transmission.~~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. ~~FirstEnergy's Risk Policy Committee, comprised~~Derivatives that fall within the scope of members of senior management, provides general management oversight for risk management activities throughout FirstEnergy. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.

~~FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet~~SFAS 133 must be recorded at their fair value ~~unless they meet~~and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal ~~purchases~~purchase and normal ~~sales criteria. Derivatives~~sale exception under SFAS 133 and are therefore excluded from the tables below. Contracts that ~~meet those criteria~~ are ~~accounted~~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 ~~at cost.~~above-market costs or regulatory liability for below-market costs. The ~~changes~~change in the fair value of commodity derivative ~~instruments~~contracts related to energy production during the first quarter of 2009 is summarized in the following table:

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, 2009	$	(304	)	$	(41	)	$	(345	)
Additions/change in value of existing contracts		(227	)		(10	)		(237	)
Settled contracts		74			22			96
Outstanding net liability as of March 31, 2009 (1)	$	(457	)	$	(29	)	$	(486	)

Non-commodity Net Liabilities as of March 31, 2009:
Interest rate swaps (2)		-			(4	)		(4	)
Net Liabilities - Derivative Contracts as of March 31, 2009	$	(457	)	$	(33	)	$	(490	)

Impact of Changes in Commodity Derivative Contracts(3)
Income Statement effects (pre-tax)	$	1		$	-		$	1
Balance Sheet effects:
Other comprehensive income (pre-tax)	$	-		$	12		$	12
Regulatory assets (net)	$	154		$	-		$	154

(1) Includes $457 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. (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, 2009 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	1		$	23		$	24
Other liabilities		(1	)		(44	)		(45	)

Non-Current-
Other deferred charges		359			-			359
Other non-current liabilities		(816	)		(12	)		(828	)

Net liabilities	$	(457	)	$	(33	)	$	(490	)

The valuation of derivative contracts is based on observable market information to the extent that dosuch information is available. In cases where such information is not ~~meet the normal purchases~~available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and ~~normal sales criteria are recorded as other expense, as AOCL, or as part~~an estimate of ~~the value~~related price volatility. FirstEnergy uses these results to develop estimates 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 financial reporting purposes and for internal management decision making (see Note 4 to the ~~right to reclaim collateral or~~consolidated financial statements). Sources of information for the ~~obligation to return collateral.~~valuation of commodity derivative contracts as of March 31, 2009 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2009(1)			2010			2011			2012			2013		Thereafter		Total
	(In millions)
Prices actively quoted(2)	$	(17	)	$	(13	)	$	-		$	-		$	-	$	-	$	(30	)
Other external sources(3)		(296	)		(241	)		(195	)		(107	)		-		-		(839	)
Prices based on models		-			-			-			-			44		339		383
Total(4)	$	(313	)	$	(254	)	$	(195	)	$	(107	)	$	44	$	339	$	(486	)

(1) For the last three quarters of 2009.

(2) Represents exchange traded NYMEX futures and options.

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

(4)

Includes $457 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.

FirstEnergy ~~hedges anticipated transactions using~~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 ~~flow hedges. Such transactions include hedges~~flows as of ~~anticipated electricity and natural gas purchases and anticipated interest payments associated with future debt issues. The effective portion~~March 31, 2009. Based on derivative contracts held as of ~~such hedges are initially recorded~~March 31, 2009, an adverse 10% change in ~~equity as other comprehensive income or loss and are subsequently included in~~commodity prices would decrease net income ~~as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings.~~

~~The net deferred losses of $78~~by approximately $1 million included in AOCL as of June 30, 2008, for derivative hedging activity, as compared to $75 million as of December 31, 2007, resulted from a net $15 million increase related to current hedging activity and a $12 million decrease due to net hedge losses reclassified to earnings during the six months ended June 30, 2008. Based on current estimates, approximately $28 million (after tax) of the net deferred losses on derivative instruments in AOCL as of June 30, 2008 are expected to be reclassified to earnings during the next ~~twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.~~12 months.

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.Forward Starting Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. As of June 30, 2008, FirstEnergy had interest rate swaps with an aggregate notional value of $150 million and a fair value of $(3) million.

Agreements - Cash Flow Hedges

~~During 2007 and the first six months of 2008,~~ FirstEnergy ~~entered into several~~utilizes forward starting swap agreements ~~(forward swaps)~~ in order to hedge a portion of the consolidated interest rate risk associated with ~~the~~ anticipated ~~issuance~~future issuances of ~~variable-rate, short-term debt and~~ fixed-rate, long-term debt securities byfor one or more of its consolidated subsidiaries ~~as outstanding debt matures during 2008~~in 2009 and ~~2009.~~2010, 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 ~~six~~three months of ~~2008,~~2009, FirstEnergy terminated forward swaps with aan aggregate notional value of ~~$650 million and entered into swaps with a notional value of $850~~$100 million. FirstEnergy paid ~~$14~~$1.3 million in cash related to the terminations, $5$0.3 million of which was deemed ineffective and recognized in current period earnings. ~~FirstEnergy~~The remaining effective portion ($1.0 million) will ~~recognize the remaining loss~~be recognized over the ~~life~~terms of the associated future debt. As of ~~June 30, 2008,~~March 31, 2009, FirstEnergy had outstanding forward swaps with an aggregate notional amount of ~~$600~~$200 million and aan aggregate fair value of $6$(4) million.

~~6. ASSET RETIREMENT OBLIGATIONS~~

	March 31, 2009							December 31, 2008
	Notional		Maturity		Fair			Notional		Maturity		Fair
Forward Starting Swaps	Amount		Date		Value			Amount		Date		Value
	(In millions)
Cash flow hedges	$	100		2009	$	(2	)		100		2009	$	(2	)
		100		2010		(2	)		100		2010		(2	)
		-		2011		-			100		2011		1
	$	200			$	(4	)		300			$	(3	)

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

The ARO of $1.3 billion as of June 30, 2008 is primarily related to the future nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of June 30, 2008, the fair value of the decommissioning trust assets was approximately $2.0 billion.

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

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

(In millions)

Balance, April 1, 2008

$
1,287

$
824

$
95

$
2

$
29

$
91

$
163

$
83

Liabilities incurred

-

-

-

-

-

-

-

-

Liabilities settled

(1
)
(1
)
-

-

-

-

-

-

Accretion

21

13

1

-

-

1

3

1

Revisions in estimated cash flows

-

-

-

-

-

-

-

-

Balance, June 30, 2008

$
1,307

$
836

$
96

$
2

$
29

$
92

$
166

$
84

Balance, April 1, 2007

$
1,208

$
772

$
89

$
2

$
27

$
86

$
153

$
78

Liabilities incurred

-

-

-

-

-

-

-

-

Liabilities settled

-

-

-

-

-

-

-

-

Accretion

21

13

2

-

-

1

3

1

Revisions in estimated cash flows

(1
)
(1
)
-

-

-

-

-

-

Balance, June 30, 2007

$
1,228

$
784

$
91

$
2

$
27

$
87

$
156

$
79

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

(In millions)

Balance, January 1, 2008

$
1,267

$
810

$
94

$
2

$
28

$
90

$
161

$
82

Liabilities incurred

-

-

-

-

-

-

-

-

Liabilities settled

(1
)
(1
)
-

-

-

-

-

-

Accretion

41

27

2

-

1

2

5

2

Revisions in estimated cash flows

-

-

-

-

-

-

-

-

Balance, June 30, 2008

$
1,307

$
836

$
96

$
2

$
29

$
92

$
166

$
84

Balance, January 1, 2007

$
1,190

$
760

$
88

$
2

$
27

$
84

$
151

$
77

Liabilities incurred

-

-

-

-

-

-

-

-

Liabilities settled

-

-

-

-

-

-

-

-

Accretion

39

25

3

-

-

3

5

2

Revisions in estimated cash flows

(1
)
(1
)
-

-

-

-

-

-

Balance, June 30, 2007

$
1,228

$
784

$
91

$
2

$
27

$
87

$
156

$
79

~~7. PENSION AND OTHER POSTRETIREMENT BENEFITS~~Equity Price Risk

FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover ~~substantially all of its subsidiaries’~~certain employees. The ~~trusteed plans provide~~plan provides defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December 31, 2007. FirstEnergy also provides ~~a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health~~health care benefits, which include certain employee contributions, deductibles, and co-payments, ~~are available~~ upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. The benefit plan assets and obligations are remeasured annually using a December 31 measurement date. Reductions in plan assets from investment losses during 2008 resulted in a decrease to the plans’ funded status of $1.7 billion and an after-tax decrease to common stockholders’ equity of $1.2 billion. As of December 31, 2008, the pension plan was underfunded and FirstEnergy ~~recognizes~~currently estimates that additional cash contributions will be required in 2011 for the ~~expected cost~~2010 plan year. The overall actual investment result during 2008 was a loss of ~~providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible~~23.8% compared to ~~receive those benefits. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.~~

~~The components of FirstEnergy's~~an assumed 9% positive return. Based on an assumed 7% discount rate, FirstEnergy’s pre-tax net periodic pension ~~cost~~ and ~~other postretirement benefit cost (including amounts capitalized) for~~OPEB expense was $43 million in the ~~three months and six months ended June 30, 2008 and 2007, consisted~~first quarter of ~~the following:~~2009.

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

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

Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. FES and the Companies capitalize employee benefits related to construction projects. The net periodic pension costs and net periodic postretirement benefit costs (including amounts capitalized) recognized by FES and each of the Companies for the three months and six months ended June 30, 2008 and 2007 were as follows:

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

2720

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

~~8. VARIABLE INTEREST ENTITIES~~

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

~~Trusts~~

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

~~PNBV was~~Nuclear decommissioning trust funds have been established to ~~purchase a portion~~satisfy NGC’s and our Utilities’ nuclear decommissioning obligations. As of March 31, 2009, approximately 31% of the ~~lease obligation bonds issued~~funds were invested in ~~connection~~equity securities and 69% were invested in fixed income securities, with ~~OE’s 1987 sale~~limitations related to concentration and ~~leaseback~~investment grade ratings. The equity securities are carried at their market value of ~~its interests~~approximately $507 million as of March 31, 2009. A hypothetical 10% decrease in ~~the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued~~prices quoted by ~~PNBV. Ownership~~stock exchanges would result in a $51 million reduction in fair value as of ~~PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary~~March 31, 2009. The decommissioning trusts of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.

~~Loss Contingencies~~

~~FES~~JCP&L and the ~~Ohio~~Pennsylvania Companies are ~~exposed~~subject to regulatory accounting, with unrealized gains and losses ~~under their applicable sale and leaseback agreements upon~~recorded as regulatory assets or liabilities, since the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments are made. The following table shows each company’s net exposure to loss based upon the casualty value provisions mentioned above as of June 30, 2008:

Maximum Exposure
Discounted
Lease Payments, net

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

~~In October 2007, CEI and TE assigned their leasehold interests~~difference between investments held in the Bruce Mansfield Plant to FGCO. FGCO assumed all of CEI’s and TE’s obligations arising under those leases. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCO’s leasehold interests under its July 2007 Bruce Mansfield Unit 1 sale and leaseback transaction to a newly formed wholly-owned subsidiary in December 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE will remain primarily liable on the 1987 leases and related agreements as to the lessors and other parties to the agreements. FGCO remains primarily liable on the 2007 leases and related agreements, and FES remains primarily liable as a guarantor under the related 2007 guarantees, as to the lessors and other parties to the respective agreements. These assignments terminate automatically upon the termination of the underlying leases.

On May 30, 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant. On June 2, 2008, NGC purchased approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. Between June 2, 2008 and June 9, 2008, NGC purchased an additional 158.5 MW of additional lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2, which purchases were undertaken in connection with the previously disclosed exercise of the periodic purchase option provided in the TE and CEI sale and leaseback arrangements. The Ohio Companies continue to lease these MW under the respective sale and leaseback arrangementstrust and the ~~related lease debt remains outstanding.~~

~~Power Purchase Agreements~~

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

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

Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it may incur for power. FirstEnergy expects any above-market costs it incurs todecommissioning liabilities will be recovered from or refunded to customers. ~~Purchased power costs from these entities during~~NGC, OE and TE recognize in earnings the ~~three months and six months ended June 30, 2008 and 2007 are shown~~unrealized losses on available-for-sale securities held in ~~the following table:~~

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

~~Transition Bonds~~

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

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of June 30, 2008, $385 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.

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

~~9. INCOME TAXES~~

On January 1, 2007, FirstEnergy adopted FIN 48, which provides guidance for accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. This interpretation prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. FIN 48 also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation is a two-step process. The first step is to determine if it is more likely than not that a tax position will be sustained upon examination,nuclear decommissioning trusts based on the ~~merits~~guidance for other-than-temporary impairments provided in SFAS 115, FSP SFAS 115-1 and SFAS 124-1. On March 27, 2009, FENOC submitted to the NRC a biennial evaluation of the ~~position,~~funding status of these trusts and ~~should therefore be recognized. The second step is to measure a tax position~~concluded that ~~meets~~ the ~~more likely than not recognition threshold to determine the amount of income tax benefit to recognize~~amounts in the ~~financial statements.~~

As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits was $268 million. FirstEnergy recorded a $2.7 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate, if recognized in 2008. The majority of items that would not affect the 2008 effective tax rate would be purchase accounting adjustments to goodwill, if recognized in 2008. During the first six months of 2008 and 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of June 30, 2008, FirstEnergy expects that it is reasonably possible that approximately $155 million of the unrecognized benefits may be resolved within the next twelve months, of which $54 million to $134 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs, capital gains and losses recognized on the disposition of assets and various other tax items.

FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. The net amount of interest accrued as of June 30, 2008 was $60 million, as compared to $53 milliontrusts as of December 31, ~~2007.~~

~~FirstEnergy has tax returns that are under review at~~2008, when coupled with the ~~audit or appeals level~~rates of return allowable by the ~~IRS~~NRC (over a safe store period for certain units) and ~~state tax authorities. All state jurisdictions~~the existing parental guarantee, would provide reasonable assurance of funding for decommissioning cost estimates under current NRC regulations. FirstEnergy does not expect to make additional cash contributions to the nuclear decommissioning trusts in 2009, other than the required annual TMI-2 trust contribution that is collected through customer rates. However, should the trust funds continue to experience declines in market value, FirstEnergy may be required to take measures, such as providing financial guarantees through LOCs or parental guarantees or making additional contributions to the trusts to ensure that the trusts are ~~open~~adequately funded and meet minimum NRC funding requirements.

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 ~~2001-2007. The IRS began reviewing returns~~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 ~~years 2001-2003 in July 2004~~purchase and ~~several items~~sale of commodities including gas, electricity, coal and emission allowances. These transactions are ~~under appeal. The federal audits for~~often with major energy companies within the years 2004-2006 are expected to close before December 2008, but management anticipates certain items to be appealed. The IRS began auditing the year 2007 in February 2007 and the year 2008 in February 2008 under its Compliance Assurance Process experimental program. Neither audit is expected to close before December 2008. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

~~10. COMMITMENTS, GUARANTEES AND CONTINGENCIES~~

~~(A) GUARANTEES AND OTHER ASSURANCES~~

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

FirstEnergy ~~guarantees energy~~maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and ~~energy-related payments~~using collateral and contract provisions to mitigate exposure. As part of its ~~subsidiaries involved in~~credit program, FirstEnergy aggressively manages the quality of its portfolio of energy ~~commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers~~contracts, evidenced by a current weighted average risk rating for energy contract counterparties of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4 billion (included in the $0.9 billion discussed above) as of June 30, 2008 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $74 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

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

~~(B)~~

~~ENVIRONMENTAL MATTERS~~

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

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

~~Clean Air Act Compliance~~

~~FirstEnergy is required to meet federally-approved SO~~2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for 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 emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.

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

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

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

~~National Ambient Air Quality Standards~~

In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR would have required reductions of NOX ~~and SO~~2 ~~emissions in two phases (Phase I in 2009 for NO~~X~~, 2010 for SO~~2 ~~and Phase II in 2015 for both NO~~X ~~and SO~~2~~), ultimately capping SO~~2 ~~emissions in affected states to just 2.5 million tons annually and NO~~X emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” The court ruling also vacated the CAIR regional cap and trade programs for SO2 ~~and NO~~X, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. The future cost of compliance with these regulations may be substantial and will depend on the action taken by the EPA or Congress in response to the Court’s ruling.

~~Mercury Emissions~~

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 ~~and NO~~X emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the court vacated the CAMR ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire court, which denied the petition on May 20, 2008. The EPA must now petition for United States Supreme Court review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

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

~~W. H. Sammis Plant~~Regulatory Matters

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX ~~and SO~~2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

~~Climate Change~~

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

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

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

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

~~Clean Water Act~~

~~Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy's plants. In addition,~~ Ohio, New Jersey and Pennsylvania, ~~have water quality standards~~laws applicable to ~~FirstEnergy's operations. As provided~~electric industry restructuring contain similar provisions that are reflected in the ~~Clean Water Act, authority~~Utilities' respective state regulatory plans. These provisions include:

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

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

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

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

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

·	requiring corporate separation of regulated and unregulated business activities.

The Utilities 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 ~~grant federal National Pollutant Discharge Elimination System water discharge permits can~~income as incurred. Regulatory assets that do not earn a current return totaled approximately $130 million as of March 31, 2009 (JCP&L - $54 million and Met-Ed - $76 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be ~~assumed~~recovered by ~~a state. Ohio, New Jersey~~2014 for JCP&L and ~~Pennsylvania have assumed such authority.~~by 2020 for Met-Ed. The following table discloses regulatory assets by company:

3321

	March 31,		December 31,		Increase
Regulatory Assets*	2009		2008		(Decrease)
	(In millions)
OE	$	545	$	575	$	(30	)
CEI		618		784		(166	)
TE		96		109		(13	)
JCP&L		1,162		1,228		(66	)
Met-Ed		490		413		77
ATSI		27		31		(4	)
Total	$	2,938	$	3,140	$	(202	)

*	Penelec had net regulatory liabilities of approximately $49 million and $137 million as of March 31, 2009 and December 31, 2008, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

Regulatory assets by source are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review one significant aspect of the Second Circuit Court’s opinion which is whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.as follows:

	March 31,			December 31,			Increase
Regulatory Assets By Source	2009			2008			(Decrease)
	(In millions)
Regulatory transition costs	$	1,437		$	1,452		$	(15	)
Customer shopping incentives		211			420			(209	)
Customer receivables for future income taxes		220			245			(25	)
Loss on reacquired debt		50			51			(1	)
Employee postretirement benefits		29			31			(2	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(56	)		(57	)		1
Asset removal costs		(225	)		(215	)		(10	)
MISO/PJM transmission costs		342			389			(47	)
Purchased power costs		305			214			91
Distribution costs		478			475			3
Other		147			135			12
Total	$	2,938		$	3,140		$	(202	)

~~Regulation of Hazardous Waste~~

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2008, FirstEnergy had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of June 30, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $95 million (JCP&L - $68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through June 30, 2008. Included in the total for JCP&L are accrued liabilities of approximately $57 million for environmental remediation of former manufactured gas plants in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

~~(C) OTHER LEGAL PROCEEDINGS~~

~~Power Outages and Related Litigation~~

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge was held on June 13, 2008. At that conference, the plaintiffs stated their intent to drop their efforts to create a class-wide damage model and, instead of dismissing the class action, expressed their desire for a bifurcated trial on liability and damages. The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario. Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure. FirstEnergy is defending this action but is unable to predict the outcome of this matter. No liability has been accrued as of June 30, 2008.

~~Nuclear Plant Matters~~

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

In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. The NRC is expected to issue its draft supplemental Environmental Impact Statement and Safety Evaluation Report with open items in 2008. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.

~~Other Legal Matters~~

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

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

On July 22, 2008 and July 23, 2008, three complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania as well as in the Beaver County Court of Common Pleas seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner,” one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. A final order identifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008. Oral arguments have been requested and are expected to take place in the fall. JCP&L recognized a liability for the potential $16 million award in 2005.

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

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

~~11. REGULATORY MATTERS~~

~~(A) RELIABILITY INITIATIVES~~

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (the PUCO, the FERC, the NERC and the U.S. – Canada Power System Outage Task Force) regarding enhancements to regional reliability. The proposed enhancements were divided into two groups: enhancements that were to be completed in 2004; and enhancements that were to be completed after 2004. In 2004, FirstEnergy completed all of the enhancements that were recommended for completion in 2004. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.

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

In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the ~~Companies~~Utilities and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including 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 the 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 result in the imposition of financial penalties and thus have a material adverse effect on its financial condition, results of operations and cash flows.

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

~~(B) OHIO~~

On ~~January 4, 2006,~~December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the ~~PUCO issued an order authorizing~~Oceanview and Atlantic substations, with customers in the ~~Ohio Companies~~affected area losing power. Power was restored to ~~recover certain increased fuel costs through~~most customers within a ~~fuel rider~~few hours and to ~~defer~~all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain ~~other increased fuel costs~~regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to ~~be incurred from January 1, 2006 through December 31, 2008, including interest on~~determine JCP&L’s contribution to the ~~deferred balances.~~electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The ~~order also provided for recovery~~initial phase of the ~~deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007,~~investigation requires JCP&L to respond to NERC’s request for factual data about the ~~Supreme Court~~outage. JCP&L submitted its written response on May 1, 2009. JCP&L is not able at this time to predict what actions, if any, that NERC will take upon receipt 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~~JCP&L’s response to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007 the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $194 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the deferred fuel costs will now be addressed in the Ohio Companies’ comprehensive ESP filing, as described below, unless the MRO is implemented.NERC’s data request.

Ohio

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. ~~In its reports,~~On January 21, 2009, the PUCO ~~Staff recommended a~~granted the Ohio Companies’ application to increase electric distribution ~~rate increase in the range~~rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and will go into effect for CEI on May 1, 2009. Applications for rehearing of ~~$161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. On January 3, 2008,~~this order were filed by the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings and filing of briefs, the PUCO Staff decreased their recommended revenue increase to a range of $117 million to $135 million. Additionally, in testimony submittedone other party on February ~~11, 2008, the~~20, 2009. The PUCO ~~Staff adopted a position regarding interest deferred~~granted these applications for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $51 million of interest costs deferred through June 30, 2008 ($0.10 per share of common stock). The Ohio Companies’ electric distribution rate request is addressed in their comprehensive ESP filing, as described below.

rehearing on March 18, 2009.

~~On May 1, 2008, Governor Strickland signed~~ SB221, which became effective on July 31, ~~2008. The bill requires~~2008, required all electric utilities to file an ESP, ~~with~~and permitted the ~~PUCO. A utility also may file~~filing of an ~~MRO in which it would have to prove the following objective market criteria:~~

·	~~the utility or its transmission service affiliate belongs to a FERC approved RTO, or there is comparable and nondiscriminatory access to the electric transmission grid;~~

·	the RTO has a market-monitor function and the ability to mitigate market power or the utility’s market conduct, or a similar market monitoring function exists with the ability to identify and monitor market conditions and conduct; and

·	a published source of information is available publicly or through subscription that identifies pricing information for traded electricity products, both on- and off-peak, scheduled for delivery two years into the future.

MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO ~~outlines a CBP that would be implemented if~~application; however, the ~~ESP is not approved by~~PUCO later granted the ~~PUCO. Under SB221, a PUCO ruling on~~Ohio Companies’ application for rehearing for the ~~ESP filing is required within 150 days and an MRO decision is required within 90 days.~~purpose of further consideration of the matter. The ESP ~~proposes~~proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and ~~would~~ resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. ~~Major provisions of~~In response to the PUCO’s December 19, 2008 order, which significantly modified and approved the ESP ~~include:~~

a phase-in of new generation rates for up to a three-year period, whereby customers would receive a 10% phase-in credit; related costs (expected to approximate $430 million in 2009, $490 million in 2010 and $550 million in 2011) would be deferred for future collection over a period not to exceed 10 years;

·	~~a reconcilable rider to recover fuel transportation cost surcharges in excess of $30 million in 2009, $20 million in 2010 and $10 million in 2011;~~

·	~~generation rate adjustments to recover any increase in fuel costs in 2011 over fuel costs incurred in 2010 for FES’ generation assets used to support~~as modified, the ~~ESP;~~

·	generation rate adjustments to recover the costs of complying with new requirements for certain renewable energy resources, new taxes and new environmental laws or new interpretations of existing laws that take effect after January 1, 2008 and exceed $50 million during the plan period;

·	~~an RCP fuel rider to recover the 2006 and 2007 deferred fuel costs and carrying charges (described above) over a period not to exceed 25 years;~~

the resolution of outstanding issues pending in the Ohio Companies’ distribution rate case (described above), including annual electric distribution rate increases of $75 million for OE, $34.5 million for CEI and $40.5 million for TE. The new distribution rates would be effective January 1, 2009, for OE and TE and May 1, 2009 for CEI, with a commitment to maintain distribution rates through 2013. CEI also would be authorized to defer $25 million in distribution-related costs incurred from January 1, 2009, through April 30, 2009;

·	~~an adjustable delivery service improvement rider, effective January 1, 2009, through December 31, 2013, to ensure the Ohio Companies maintain customer standards for service and reliability;~~

·	the waiver of RTC charges for CEI’s customers as of January 1, 2009, which would result in CEI’s write-off of approximately $485 million of estimated unrecoverable transition costs ($1.01 per share of common stock);

the continued recovery of transmission costs, including MISO, ancillary services and congestion charges, through an annually adjusted transmission rider; a separate rider will be established to recover costs incurred annually between May 1st ~~and September 30~~th ~~for capacity purchases required to meet FERC, NERC, MISO and other applicable standards for planning reserve margin requirements;~~

a deferred transmission cost recovery rider effective January 1, 2009, through December 31, 2010 to recover transmission costs deferred by the Ohio Companies in 2005 and accumulated carrying charges through December 31, 2008; a deferred distribution cost recovery rider effective January 1, 2011, to recover distribution costs deferred under the RCP, CEI’s additional $25 million of cost deferrals in 2009, line extension deferrals and transition tax deferrals;

the deferral of annual storm damage expenses in excess of $13.9 million, certain line extension costs, as well as depreciation, property tax obligations and post in-service carrying charges on energy delivery capital investments for reliability and system efficiency placed in service after December 31, 2008. Effective January 1, 2014, a rider will be established to collect the deferred balance and associated carrying charges over a 10-year period; and

·	a commitment by the Ohio Companies to invest in aggregate at least $1 billion in capital improvements in their energy delivery systems through 2013 and fund $25 million for energy efficiency programs and $25 million for economic development and job retention programs through 2013.

~~The~~ Ohio ~~Companies’ MRO filing outlines~~Companies notified the PUCO that they were withdrawing and terminating the ESP application in addition to continuing their current rate plan in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for ~~providing~~the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. The average winning bid price was equivalent to a retail rate of 6.98 cents per kwh. The power supply obtained through this process provides generation ~~supply if the ESP is not approved and implemented. The CBP would use a “slice-of-system” approach where suppliers bid on tranches (approximately 100 MW) of~~service to the Ohio Companies’ ~~total customer load. The~~retail customers who choose not to shop with alternative suppliers. On January 9, 2009, the Ohio Companies ~~have~~ requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ~~approval~~ultimately approved the Ohio Companies’ request for a new fuel rider to recover increased costs resulting from the CBP but did not authorize OE and TE to continue collecting RTC or allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider allows for current recovery of the ~~MRO application by late October 2008,~~increased purchased power costs for OE and TE, and authorizes CEI to ~~allow~~collect a portion of those costs currently and defer the remainder for future recovery.

On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the ~~necessary time to conduct~~Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP provides that generation will be provided by FES at the average wholesale rate of the CBP ~~in order~~process described above for rates to be effective January 1, 2009. The Ohio Companies included an interim pricing proposal as part of their ESP filing, if additional time is necessary for final PUCO approval of either the ESP or MRO. FES will be required to obtain FERC authorization to sell electric capacity or energyApril and May 2009 to the Ohio Companies ~~under~~for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices will be based upon the outcome of a descending clock CBP on a slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of any increase resulting from this CBP process by authorizing deferral of related purchased power costs, subject to specified limits. The Amended ESP further provides that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI will agree to write-off approximately $216 million of its Extended RTC balance, and that the Ohio Companies will collect a delivery service improvement rider at an overall average rate of $.002 per kWh for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addresses a number of other issues, including but not limited to, rate design for various customer classes, resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or ~~MRO, unless~~not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation take effect on April 1, 2009 while the remaining provisions take effect on June 1, 2009. The CBP auction is currently scheduled to begin on May 13, 2009. The bidding will occur for a ~~waiver is obtained.~~single, two-year product and there will not be a load cap for the bidders. FES may participate without limitation.

SB221 also requires electric distribution utilities to implement energy efficiency programs that achieve an energy savings equivalent of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013. Utilities are also required to reduce peak demand in 2009 by one percent, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. Costs associated with compliance are recoverable from customers.

~~(C) PENNSYLVANIA~~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~~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.

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

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 May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against ~~Met-Ed’s and Penelec’s TSC~~those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing ~~the company~~Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was ~~adopted with hearings~~adopted. Hearings and briefing for both Met-Ed and Penelec have concluded and the companies ~~scheduled to begin in January 2009.~~are awaiting a Recommended Decision from the ALJ. The TSCs include a component ~~for~~from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval ~~from the PPUC of~~for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.

On ~~March 13, 2008,~~April 15, 2009, Met-Ed and Penelec filed revised TSCs with 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~~2009 through May 31, ~~2011.~~2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers, the new TSC would result in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The ~~PPUC had previously approved~~TSC for Met-Ed’s customers would increase to recover 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. Bidsadditional PJM charges paid by Met-Ed in the ~~two RFPs~~previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, Met-Ed is proposing to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs into a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for ~~small commercial~~Met-Ed’s customers would increase approximately 9.4% for the period June 2009 through May 2010.

On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. The bill addresses issues such as: energy efficiency and peak load ~~were approved by~~reduction; generation procurement; time-of-use rates; smart meters and alternative energy. Act 129 requires utilities to file with the PPUC ~~on February 22, 2008,~~an energy efficiency and ~~March 20, 2008.~~peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009. On ~~March 28, 2008, Penn filed~~January 15, 2009, in compliance ~~tariffs~~ with ~~the new default service generation rates based on the approved RFP bids for small commercial customers which~~Act 129, the PPUC ~~then certified~~issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. Similar guidelines related to Smart Meter deployment were issued for comment on ~~April 4, 2008. Bids on~~March 30, 2009.

Major provisions of the ~~two RFPs for residential customers’ load were~~legislation include:

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

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

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

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

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

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

Legislation addressing rate mitigation and the ~~PPUC on April 16, 2008~~expiration of rate caps was not enacted in 2008; however, several bills addressing these issues have been introduced in the current legislative session, which began in January 2009. The final form and May 16, 2008. On May 20, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for residential customers which the PPUC certified on May 21, 2008. The new rates were effective June 1, 2008.impact of such legislation is uncertain.

On February 26, 2009, the PPUC approved a Voluntary Prepayment Pan requested by Met-Ed and Penelec that provides an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010. Customer prepayments earn interest at 7.5% and will be used to reduce electricity charges in 2011 and 2012.

On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, ~~2007, the Governor of Pennsylvania proposed an EIS.~~2011 through May 31, 2013. The ~~EIS includes four pieces of proposed legislation that, according to the Governor,~~companies’ plan is designed to ~~reduce energy costs, promote energy independence~~provide adequate and ~~stimulate~~reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class, through the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. As part of the 2008 state budget negotiations, the Alternative Energy Investment Act was enacted creating a $650 million alternative energy fund to increase the development and use of alternative and renewable energy, improve energy efficiency and reduce energy consumption. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy; however, consideration of these issues was postponed until the legislature returns to session in fall 2008. The final form of this pending legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations. However,a descending clock auction. Met-Ed and Penelec ~~intend~~have requested PPUC approval of their plan by November 2009.

On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance Filing to ~~file rate mitigation plans with~~ the PPUC ~~later~~in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $51 million), overall rates would remain unchanged. The PPUC must act on this ~~year.~~filing within 120 days.

~~(D) NEW JERSEY~~New Jersey

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, ~~and~~ costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of ~~June 30, 2008,~~March 31, 2009, the accumulated deferred cost balance totaled approximately ~~$293~~$165 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~~DPA 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 March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.

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. AFollowing public hearing ~~on these proposed rules was held on April 23, 2008~~ and consideration of comments from interested parties, ~~were submitted by May 19, 2008.~~the NJBPU approved final regulations effective April 6, 2009. These regulations are not expected to materially impact FirstEnergy or JCP&L.

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the first half of 2008.

~~On April 17, 2008, a draft~~

The EMP was ~~released for public comment. The draft EMP establishes~~issued on October 22, 2008, establishing five major goals:

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

·	reduce peak demand for electricity by 5,700 MW by 2020;

·	meet ~~22.5%~~30% of the state’s electricity needs with renewable energy by 2020;

·	examine smart grid technology and develop ~~low carbon emitting, efficient power plants~~additional cogeneration and ~~close~~other generation resources consistent with the ~~gap between the supply and demand for electricity;~~state’s greenhouse gas targets; and

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

~~Following~~On January 28, 2009, the ~~public hearings~~NJBPU adopted an order establishing the general process and ~~comment period which extended into July 2008, a final~~contents of specific EMP ~~will~~plans that must be ~~issued~~filed by December 31, 2009 by New Jersey electric and gas utilities in order to ~~be followed by appropriate legislation and regulation as necessary.~~achieve the goals of the EMP. At this time, FirstEnergy cannot ~~predict the outcome of this process nor~~ determine the impact, if any, ~~such legislation or regulation~~the EMP may have on its operations or those of JCP&L.

In support of the New Jersey Governor’s Economic Assistance and Recovery Plan, JCP&L announced its intent to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. An estimated $40 million will be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. Approximately $34 million will be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million will be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million will be spent on energy efficiency programs that will complement those currently being offered. Completion of the projects is dependent upon resolution of regulatory issues including recovery of the costs associated with plan implementation.

~~(E)~~ FERC ~~MATTERS~~Matters

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or ~~“SECA”)~~SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order ~~could be issued by~~is pending before the FERC, ~~by year-end 2008. In~~and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order.

On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.

PJM Transmission Rate ~~Design~~

On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. 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. On February 11, 2008, AEP appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit. Oral argument was held on April 13, 2009, and a decision is expected this summer.

The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce the costs of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding ~~Judge. The FERC’s action on~~Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement ~~agreement is pending.~~subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. ~~Reply briefs and briefs on exceptions are due in the merchant proceeding in July and August, respectively, with an~~An initial decision was issued by the Presiding Judge ~~to follow. On February 11, 2008, AEP appealed the FERC’s April 19, 2007~~on September 18, 2008. PJM and ~~January 31, 2008 orders~~FERC trial staff each filed a Brief on Exceptions 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.initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.

Post Transition Period Rate Design

The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within 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. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP ~~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 1, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.

On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepteddenied by the FERC on ~~March 13,~~December 19, 2008. On ~~that same day, MISO~~February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the ~~MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution~~U.S. Court of ~~transmission revenues that was in effect prior to February 1, 2008. On May 12, 2008, the FERC issued an order approving this amendment.~~

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

MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authorityAppeals for the region. This filing would permit load serving entities to purchase their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. Numerous parties filed requests for rehearing on March 26, 2008. On June 23, 2008, the FERC issued an order granting in part and denying in part rehearing. MISO has since notified the FERC that the start of its ASM will be delayed until September 9, 2008.

On February 29, 2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor ASM and Consolidated Balancing Authority Initiative Verification plan and status and Real-Time Operations ASM Reversion plan. FERC action on this compliance filing remains pending. On March 26, 2008, MISO submitted a tariff filing in compliance with the FERC’s 30-day directives in the February 25 order. Numerous parties submitted comments and protests on April 16, 2008. The FERC issued an order accepting the revisions pending further compliance on June 23, 2008. On April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s 60-day directives in the February 25 order. FERC action on this compliance filing remains pending. On May 23, 2008, MISO submitted its amended Balancing Authority Agreement. On July 21, 2008, the FERC issued an order conditionally accepting the amended Balancing Authority Agreement and requiring a further compliance filing.

~~Interconnection Agreement with AMP-Ohio~~

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

On May 29, 2008, TE filed with the FERC a proposed Notice of Cancellation effective midnight December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio protested this filing. TE also filed a Petition for Declaratory Order seeking a FERC ruling, in the alternative if cancellation is not accepted, of TE's right to file for an increase in rates effective January 1, 2009, for power provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a pleading agreeing that TE may seek an increase in rates, but arguing that any increase is limited to the cost of generation owned by TE affiliates. TE has requested FERC action on both filings and expects the FERC to act on this request in the third quarter of 2008.10, 2009.

Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join MISO. ~~In its filing, Duquesne asked~~Duquesne’s proposed move would affect numerous FirstEnergy interests, including but not limited to 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 theterms under which FirstEnergy’s Beaver Valley Plant would continue to ~~meet existing commitments~~participate in PJM’s energy markets. FirstEnergy, therefore, intervened and participated fully in all of the ~~PJM capacity markets and~~FERC dockets that were related to ~~serve native load. Other market participants also submitted filings contesting~~ Duquesne’s ~~plans.~~proposed move.

~~On January 17,~~In November, 2008, ~~the FERC conditionally approved Duquesne’s request to exit PJM. Among~~Duquesne and other ~~conditions, the FERC obligated~~parties, including FirstEnergy, negotiated a settlement that would, among other things, allow for Duquesne to ~~pay~~remain in PJM and provide for a methodology for Duquesne to meet the PJM capacity obligations ~~through May 31, 2011.~~for the 2011-2012 auction that excluded the Duquesne load. The ~~FERC’s~~settlement agreement was filed on December 10, 2008 and approved by the FERC in an order ~~took notice~~issued on January 29, 2009. MISO opposed the settlement agreement pending resolution of exit fees alleged to be owed by Duquesne. The FERC did not resolve the exit fee issue in its order. On March 2, 2009, the PPUC filed for rehearing of the ~~numerous transmission and other issues raised by~~FERC's January 29, 2009 order approving the settlement. Thereafter, FirstEnergy and other parties filed in opposition to the ~~proceeding, but did not provide any responsive rulings or other guidance. Rather,~~rehearing request. The PPUC's rehearing request, and the ~~FERC ordered Duquesne to make a compliance filing~~pleadings in ~~forty-five days detailing how Duquesne will satisfy its obligations under~~opposition thereto, are pending before the PJM Transmission Owners’ Agreement. The FERC likewise directed MISO to submit detailed plans to integrate Duquesne into MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 1, 2008. On July 3, 2008, Duquesne and MISO filed a proposed plan for integrating Duquesne into MISO. On July 24, 2008, numerous parties filed comments and protests to the proposed plan. FirstEnergy filed comments identifying numerous issues that must be addressed and resolved before Duquesne can transition to MISO. FirstEnergy continues to evaluate the impact of Duquesne’s withdrawal from PJM on its operations and financial condition; however, the full consequences cannot be determined until the FERC rules on the pending issues.FERC.

On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators could contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with the FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. Given that the FERC outlined the conditions under which FirstEnergy could bid the unit into the auction and FirstEnergy complied with the FERC’s conditions, FirstEnergy does not anticipate that the FERC will grant the relief requested in the pleadings. Based on this expectation, FirstEnergy believes that the auction results would not be changed.

~~Complaint against~~Changes ordered for PJM ~~RPM~~Reliability Pricing Model (RPM) Auction

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. ~~Most~~On September 19, 2008, the FERC denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’ request for a technical conference to review aspects of the ~~parties comprising~~RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM Buyers group were parties to the settlement approved by the FERC that established the RPM. In the complaint, the RPM Buyers request that the total projected payments to RPM sellers for the three auctions at issue be materially reduced.program as suggested in a Brattle Group report. On ~~July 11,~~December 12, 2008, PJM filed ~~its answer to~~proposed tariff amendments that would adjust slightly the ~~complaint, in which it denied the allegation that the rates are unjust and unreasonable. Also on that date, FirstEnergy filed a motion to intervene.~~

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

~~FES believes~~program. PJM also requested that the FERC ~~is unlikely~~conduct a settlement hearing to ~~grant~~address changes to the ~~relief sought~~RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement talks. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.

On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. Ordered changes included making incremental improvements to RPM; however, the basic construct of RPM remains intact. On April 3, 2009, PJM filed with the FERC requesting clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the ~~RPM Buyers’ complaint, since it largely deals with legal issues concerning the fundamentals~~March 26, 2009 Order; numerous parties have filed requests for rehearing of the March 26, 2009 Order. In addition, the FERC has indefinitely postponed the technical conference on RPM ~~markets that are already at issue~~granted in ~~a separate D.C. Circuit Court appellate proceeding. Nevertheless, FES is unable to predict~~ the ~~outcome~~FERC order of ~~these proceedings or the resulting effect on FirstEnergy’s or FES’ results of operations, cash flows or financial position.~~September 19, 2008.

MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for ~~load serving~~load-serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for ~~load serving~~load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for ~~load serving~~load-serving entities in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were ~~filed~~submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for ~~load serving~~load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing. ~~A FERC decision on this filing is expected this fall.~~

~~Organized Wholesale Power Markets~~

On ~~February 21,~~October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a ~~NOPR~~compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process is expected to start as planned effective June 1, 2009, the beginning of the MISO planning year.

FES Sales to Affiliates

On October 24, 2008, FES, on its own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies after January 1, 2009 pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. On December 23, 2008, the FERC issued an order granting the waiver request and the Ohio Companies made the required compliance filing on December 30, 2008. In January 2009, several parties filed for rehearing of the FERC’s December 23, 2008 order. In response, FES filed an answer to requests for rehearing on February 5, 2009. The requests and responses are pending before the FERC.

FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through ~~which it proposes~~March 31, 2009. Subsequently, FES signed an agreement to ~~adopt new rules~~provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of the December 23, 2008 waiver.

On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and Waverly effective November 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be supplied by FES in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the default or failure of supply of their committed resources. Prices for the power provided by FES were not changed in the Third Restated Partial Requirements Agreement.

Environmental Matters

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 $37,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. 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.

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, the generation of more electricity at lower-emitting plants, and/or using emission allowances. 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.

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $706 million for 2009-2012 (with $414 million expected to be spent in 2009).

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 ~~“improve operations~~continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in ~~organized~~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. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints. The Pennsylvania Department of Health and the U.S. Agency for Toxic Substance and Disease Registry recently disclosed their intention to conduct additional air monitoring in the vicinity of the Mansfield plant.

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 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint on February 19, 2009. On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.

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

On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. FGCO intends to fully comply with the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter.

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

National Ambient Air Quality Standards

In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. The future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric ~~markets, boost competition~~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 ~~bring additional benefits~~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 ~~consumers.”~~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 ~~proposed~~EPA petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. The EPA is developing 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 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. FirstEnergyfor EPA approval that does not ~~believe~~provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the ~~proposed~~Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule ~~will~~was 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.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration had committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, former President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity in the United States comes from renewable sources by 2012, and increasing to 25% by 2025; and implementing an economy-wide cap-and-trade program to reduce GHG emissions 80% by 2050.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a ~~significant impact on its operations. Comments on~~two-year process designed to lead to an agreement in 2009. At the ~~NOPR were filed on April 21, 2008.~~federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environment and Public Works Committee has passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

~~12.~~

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. On April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA’s proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources.

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 to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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

Regulation of Waste Disposal

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. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. The future cost of compliance with coal combustion waste regulations may be substantial and will depend, in part, on the regulatory action taken by the EPA and implementation by the states.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, 2009, FirstEnergy had approximately $1.6 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 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 Utilities have been named as potentially responsible parties 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 potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $91 million have been accrued through March 31, 2009. Included in the total are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants and gas holder facilities 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, the Muise class action) 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.

After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only 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 which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. Proceedings then continued at the trial court level and a case management conference with the presiding Judge was held on June 13, 2008. At that conference, counsel for the Plaintiffs stated his intent to drop his efforts to create a class-wide damage model and, instead of dismissing the class action, expressed his desire for a bifurcated trial on liability and damages. In response, JCP&L filed an objection to the plaintiffs’ proposed trial plan and another motion to decertify the class. On March 31, 2009, the trial court granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed their appeal to the trial court's decision to decertify the class.

Nuclear Plant Matters

On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for Information 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 response to the NRC on July 16, 2007. The NRC issued a Confirmatory Order imposing these commitments on FENOC. In an April 23, 2009 Inspection Report, the NRC concluded that FENOC had completed all necessary actions required by the Confirmatory Order.

In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.

Other Legal Matters

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. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009; the appeal process could take as long as 24 months. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.

The union employees at Met-Ed have been working without a labor contract since May 1, 2009. The parties are continuing to bargain and FirstEnergy has a work continuation plan ready in the event of a strike.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

~~SFAS 141(R)~~FSP FAS 157-4 – ~~“Business Combinations”~~“Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”

In ~~December 2007,~~April 2009, the FASB issued ~~SFAS 141(R), which: (i) requires~~Staff Position FAS 157-4, which provides additional guidance to consider in estimating fair value when there has been a significant decrease in market activity for a financial asset. The FSP establishes a two-step process requiring a reporting entity to first determine if a market is not active in relation to normal market activity for the ~~acquiring~~asset. If evidence indicates the market is not active, an entity inwould then need to determine whether a ~~business combination to recognize all the assets acquired and liabilities assumed~~quoted price in the ~~transaction; (ii) establishes~~market is associated with a distressed transaction. An entity will need to further analyze the ~~acquisition-date~~transactions or quoted prices, and an adjustment to the transactions or quoted prices may be necessary to estimate fair value. Additional disclosures related to the inputs and valuation techniques used in the fair value as the measurement objective for all assets acquired and liabilities assumed; and (iii) requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination.measurements are also required. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

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

In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This StatementFSP is effective for ~~fiscal years,~~interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim ~~periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is~~period ending June 30, 2009. While the FSP will expand disclosure requirements, FirstEnergy does not ~~expected~~expect the FSP to have a material ~~impact on FirstEnergy’s~~effect upon its financial statements.

FSP FAS 115-2 and FAS 124-2 - “Recognition and Presentation of Other-Than-Temporary Impairments”

In April 2009, the FASB issued Staff Position FAS 115-2 and FAS 124-2, which changes the method to determine whether an other-than-temporary impairment exists for debt securities and the amount of impairment to be recorded in earnings. Under the FSP, management will be required to assert it does not have the intent to sell the debt security, and it is more likely than not it will not have to sell the debt security before recovery of its cost basis. If management is unable to make these assertions, the debt security will be deemed other-than-temporarily impaired and the security will be written down to fair value with the full charge recorded through earnings. If management is able to make the assertions, but there are credit losses associated with the debt security, the portion of impairment related to credit losses will be recognized in earnings while the remaining impairment will be recognized through other comprehensive income. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009 and does not expect the FSP to have a material effect upon its financial statements.

FSP FAS 107-1 and APB 28-1 - “Interim Disclosures about Fair Value of Financial Instruments”

In April 2009, the FASB issued Staff Position FAS 107-1 and APB 28-1, which requires disclosures of the fair value of financial instruments in interim financial statements, as well as in annual financial statements. The FSP also requires entities to disclose the methods and significant assumptions used to estimate the fair value of financial instruments in both interim and annual financial statements. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009, and expects to expand its disclosures regarding the fair value of financial instruments.

FSP FAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”

In December 2008, the FASB issued Staff Position FAS 132(R)-1, which provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This FSP is effective for fiscal years ending after December 15, 2009. FirstEnergy will expand its disclosures related to postretirement benefit plan assets as a result of this FSP.

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, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 6 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 7, 2009

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended
	March 31

	2009			2008
	(In millions, except
	per share amounts)
REVENUES:
Electric utilities	$	3,020		$	2,913
Unregulated businesses		314			364
Total revenues*		3,334			3,277

EXPENSES:
Fuel		312			328
Purchased power		1,143			1,000
Other operating expenses		827			799
Provision for depreciation		177			164
Amortization of regulatory assets		411			258
Deferral of new regulatory assets		(93	)		(105	)
General taxes		211			215
Total expenses		2,988			2,659

OPERATING INCOME		346			618

OTHER INCOME (EXPENSE):
Investment income (loss), net		(11	)		17
Interest expense		(194	)		(179	)
Capitalized interest		28			8
Total other expense		(177	)		(154	)

INCOME BEFORE INCOME TAXES		169			464

INCOME TAXES		54			187

NET INCOME		115			277

Less: Noncontrolling interest income (loss)		(4	)		1

EARNINGS AVAILABLE TO PARENT	$	119		$	276


BASIC EARNINGS PER SHARE OF COMMON STOCK	$	0.39		$	0.91

WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		304			304

DILUTED EARNINGS PER SHARE OF COMMON STOCK	$	0.39		$	0.90

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		306			307

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.55		$	0.55


* Includes $109 million and $114 million of excise tax collections in the first quarter of 2009 and 2008, 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
	2009			2008
	(In millions)

NET INCOME	$	115		$	277

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		35			(20	)
Unrealized gain (loss) on derivative hedges		15			(13	)
Change in unrealized gain on available-for-sale securities		(5	)		(58	)
Other comprehensive income (loss)		45			(91	)
Income tax expense (benefit) related to other comprehensive income		15			(33	)
Other comprehensive income (loss), net of tax		30			(58	)

COMPREHENSIVE INCOME		145			219

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		(4	)		1

COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT	$	149		$	218

The accompanying 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,
	2009			2008
	(In millions)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	399		$	545
Receivables-
Customers (less accumulated provisions of $27 million and $28 million,
respectively, for uncollectible accounts)		1,266			1,304
Other (less accumulated provisions of $9 million for uncollectible accounts)		159			167
Materials and supplies, at average cost		657			605
Prepaid taxes		318			283
Other		205			149
		3,004			3,053
PROPERTY, PLANT AND EQUIPMENT:
In service		26,757			26,482
Less - Accumulated provision for depreciation		10,947			10,821
		15,810			15,661
Construction work in progress		2,397			2,062
		18,207			17,723
INVESTMENTS:
Nuclear plant decommissioning trusts		1,649			1,708
Investments in lease obligation bonds		561			598
Other		689			711
		2,899			3,017
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,575			5,575
Regulatory assets		2,938			3,140
Power purchase contract asset		340			434
Other		594			579
		9,447			9,728
	$	33,557		$	33,521
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	2,144		$	2,476
Short-term borrowings		2,397			2,397
Accounts payable		704			794
Accrued taxes		281			333
Other		1,169			1,098
		6,695			7,098
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 375,000,000 shares-		31			31
304,835,407 shares outstanding
Other paid-in capital		5,459			5,473
Accumulated other comprehensive loss		(1,350	)		(1,380	)
Retained earnings		4,110			4,159
Total common stockholders' equity		8,250			8,283
Noncontrolling interest		34			32
Total equity		8,284			8,315
Long-term debt and other long-term obligations		9,697			9,100
		17,981			17,415
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,130			2,163
Asset retirement obligations		1,356			1,335
Deferred gain on sale and leaseback transaction		1,018			1,027
Power purchase contract liability		816			766
Retirement benefits		1,896			1,884
Lease market valuation liability		296			308
Other		1,369			1,525
		8,881			9,008
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
	$	33,557		$	33,521

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

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In millions)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	115		$	277
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		177			164
Amortization of regulatory assets		411			258
Deferral of new regulatory assets		(93	)		(105	)
Nuclear fuel and lease amortization		27			26
Deferred purchased power and other costs		(62	)		(43	)
Deferred income taxes and investment tax credits, net		(28	)		89
Investment impairment		36			16
Deferred rents and lease market valuation liability		(14	)		4
Stock-based compensation		(13	)		(35	)
Accrued compensation and retirement benefits		(66	)		(142	)
Gain on asset sales		(5	)		(37	)
Electric service prepayment programs		(8	)		(19	)
Cash collateral received (paid)		(15	)		8
Decrease (increase) in operating assets-
Receivables		46			(6	)
Materials and supplies		(7	)		(17	)
Prepaid taxes		(34	)		(100	)
Increase (decrease) in operating liabilities-
Accounts payable		(90	)		(23	)
Accrued taxes		(51	)		(5	)
Accrued interest		118			91
Other		18			(42	)
Net cash provided from operating activities		462			359

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		700			-
Short-term borrowings, net		-			746
Redemptions and Repayments-
Long-term debt		(444	)		(368	)
Net controlled disbursement activity		(10	)		6
Common stock dividend payments		(168	)		(168	)
Other		(8	)		8
Net cash provided from financing activities		70			224

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(654	)		(711	)
Proceeds from asset sales		8			50
Sales of investment securities held in trusts		567			361
Purchases of investment securities held in trusts		(584	)		(384	)
Cash investments		17			58
Other		(32	)		(16	)
Net cash used for investing activities		(678	)		(642	)

Net change in cash and cash equivalents		(146	)		(59	)
Cash and cash equivalents at beginning of period		545			129
Cash and cash equivalents at end of period	$	399		$	70

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

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 and maintains 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 have been primarily derived 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 and default service requirements. These affiliated power sales included a full-requirements PSA with OE, CEI and TE to supply each of their default service obligations through December 31, 2008, at prices that considered their respective PUCO-authorized billing rates. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond. FES continues to have a partial requirements wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to supply a portion of each of their respective default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty-day written notice prior to the end of the calendar year. FES also supplies, through May 31, 2009, a portion of Penn’s default service requirements at market-based rates as a result of Penn’s 2008 competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois. These sales may provide a greater portion of revenues in future years depending upon FES’ participation in its Ohio and Pennsylvania utility affiliates’ power procurement arrangements.

Results of Operations

In the first three months of 2009, net income increased to $171 million from $90 million in the same period in 2008. The increase in net income was primarily due to higher revenues and lower fuel and purchased power costs, partially offset by higher other operating expenses, depreciation and other miscellaneous expenses.

Revenues

Revenues increased by $127 million in the first three months of 2009 compared to the same period in 2008 due to increases in revenues from non-affiliated and affiliated wholesale generation sales, partially offset by lower retail generation sales. The increase in revenues resulted from the following sources:

	Three Months Ended
	March 31				Increase
Revenues by Type of Service	2009		2008		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	91	$	160	$	(69	)
Wholesale		189		129		60
Total Non-Affiliated Generation Sales		280		289		(9	)
Affiliated Generation Sales		893		776		117
Transmission		25		33		(8	)
Other		28		1		27
Total Revenues	$	1,226	$	1,099	$	127

Retail generation sales revenues decreased due to reduced commercial and industrial contract renewals in the PJM market and the termination of certain government aggregation programs in the MISO market that were supplied by FES. Non-affiliated wholesale revenues increased due to higher PJM capacity prices and increased sales volumes in the MISO market, partially offset by lower unit prices and volumes in PJM.

Increased affiliated company wholesale revenues resulted from higher unit prices for sales to the Ohio Companies, under their CBP, partially offset by lower composite prices to the Pennsylvania Companies and an overall decrease in affiliated sales volumes. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the overall composite price to decline. FES supplied less power to the Ohio Companies in the first quarter of 2009 as one of four winning bidders in the Ohio Companies’ RFP process.

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 2009 compared to the same period last year:

	Increase
Source of Change in Non-Affiliated Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 57.0% decrease in sales volumes	$	(91	)
Change in prices		22
		(69	)
Wholesale:
Effect of 33.9% increase in sales volumes		44
Change in prices		16
		60
Net Decrease in Non-Affiliated Generation Revenues	$	(9	)

	Increase
Source of Change in Affiliated Generation Revenues	(Decrease)
	(In millions)
Ohio Companies:
Effect of 24.6% decrease in sales volumes	$	(142	)
Change in prices		246
		104
Pennsylvania Companies:
Effect of 11.1% increase in sales volumes		22
Change in prices		(9	)
		13
Net Increase in Affiliated Generation Revenues	$	117

Transmission revenue decreased $8 million due to decreased retail load in the MISO market ($14 million), partially offset by higher PJM congestion revenues ($6 million). Other revenue increased $27 million primarily due to NGC’s lease revenue received from its equity interests in the Beaver Valley Unit 2 and Perry sale and leaseback transactions acquired during the second quarter of 2008.

Expenses

Total expenses decreased by $1 million in the first three months of 2009 compared with the same period of 2008. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first three months of 2009 from the same period last year:

Source of Change in Fuel and Purchased Power	Increase (Decrease)
	(In millions)
Fossil Fuel:
Change due to increased unit costs	$	36
Change due to volume consumed		(52	)
		(16	)
Nuclear Fuel:
Change due to increased unit costs		1
Change due to volume consumed		-
		1
Non-affiliated Purchased Power:
Change due to decreased unit costs		(15	)
Change due to volume purchased		(31	)
		(46	)
Affiliated Purchased Power:
Change due to increased unit costs		40
Change due to volume purchased		(3	)
		37
Net Decrease in Fuel and Purchased Power Costs	$	(24	)

Fossil fuel costs decreased $16 million in the first three months of 2009 primarily as a result of decreased coal consumption, reflecting lower generation. Higher unit prices were due to increased fuel rates on existing coal contracts in the first quarter of 2009. Nuclear fuel costs were relatively unchanged in the first quarter of 2009 from last year.

Purchased power costs from non-affiliates decreased primarily as a result of lower market rates and reduced volume requirements. Purchases from affiliated companies increased as a result of higher unit costs on purchases from the Ohio Companies’ leasehold interests in Beaver Valley Unit 2 and Perry.

Other operating expenses increased by $11 million in the first three months of 2009 from the same period of 2008. The increase was primarily due to 2009 organizational restructuring costs ($4 million) and nuclear operating costs as a result of higher expenses associated with the 2009 Perry refueling outage than incurred with the 2008 Davis-Besse refueling outage ($11 million). Transmission expenses increased as a result of higher congestion charges ($7 million). Partially offsetting the increases were lower fossil contractor costs as a result of rescheduled maintenance activities ($7 million) and lower lease expenses relating to CEI’s and TE’s leasehold improvements in the Mansfield Plant that were transferred to FGCO during the first quarter of 2008 ($5 million).

Depreciation expense increased by $12 million in the first three months of 2009 primarily due to NGC’s acquisition of certain lessor equity interests in the sale and leaseback of Perry and Beaver Valley Unit 2 ($7 million) and property additions since the first quarter of 2008.

Other Expense

Other expense increased by $14 million in the first three months of 2009 from the same period of 2008 primarily due to a greater loss in value of nuclear decommissioning trust investments ($23 million) during the first quarter of 2009. Partially offsetting the higher securities impairments was a $10 million decline in interest expense as a result of higher capitalized interest ($3 million) and lower interest expense to affiliates due to lower rates on loans from the unregulated moneypool ($4 million).

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, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, 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, 2008, 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, 2009

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)


REVENUES:
Electric sales to affiliates	$	892,690		$	776,307
Electric sales to non-affiliates		279,746			288,341
Other		53,670			34,468
Total revenues		1,226,106			1,099,116

EXPENSES:
Fuel		306,158			321,689
Purchased power from non-affiliates		160,342			206,724
Purchased power from affiliates		63,207			25,485
Other operating expenses		307,356			296,546
Provision for depreciation		61,373			49,742
General taxes		23,376			23,197
Total expenses		921,812			923,383

OPERATING INCOME		304,294			175,733

OTHER EXPENSE:
Miscellaneous expense		(26,363	)		(2,904	)
Interest expense to affiliates		(2,979	)		(7,210	)
Interest expense - other		(22,527	)		(24,535	)
Capitalized interest		10,078			6,663
Total other expense		(41,791	)		(27,986	)

INCOME BEFORE INCOME TAXES		262,503			147,747

INCOME TAXES		91,822			57,763

NET INCOME		170,681			89,984

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		2,568			(1,820	)
Unrealized gain on derivative hedges		11,016			5,718
Change in unrealized gain on available-for-sale securities		(1,477	)		(51,852	)
Other comprehensive income (loss)		12,107			(47,954	)
Income tax expense (benefit) related to other comprehensive income		4,709			(17,403	)
Other comprehensive income (loss), net of tax		7,398			(30,551	)

TOTAL COMPREHENSIVE INCOME	$	178,079		$	59,433

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

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	34		$	39
Receivables-
Customers (less accumulated provisions of $3,994,000 and $5,899,000,
respectively, for uncollectible accounts)		54,554			86,123
Associated companies		287,935			378,100
Other (less accumulated provisions of $6,702,000 and $6,815,000
respectively, for uncollectible accounts)		66,293			24,626
Notes receivable from associated companies		433,137			129,175
Materials and supplies, at average cost		567,687			521,761
Prepayments and other		112,162			112,535
		1,521,802			1,252,359
PROPERTY, PLANT AND EQUIPMENT:
In service		9,912,603			9,871,904
Less - Accumulated provision for depreciation		4,327,241			4,254,721
		5,585,362			5,617,183
Construction work in progress		2,114,831			1,747,435
		7,700,193			7,364,618
INVESTMENTS:
Nuclear plant decommissioning trusts		995,476			1,033,717
Long-term notes receivable from associated companies		62,900			62,900
Other		31,898			61,591
		1,090,274			1,158,208
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		241,607			267,762
Lease assignment receivable from associated companies		71,356			71,356
Goodwill		24,248			24,248
Property taxes		50,104			50,104
Unamortized sale and leaseback costs		86,302			69,932
Other		87,141			96,434
		560,758			579,836
	$	10,873,027		$	10,355,021
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	1,690,942		$	2,024,898
Short-term borrowings-
Associated companies		786,116			264,823
Other		1,100,000			1,000,000
Accounts payable-
Associated companies		409,160			472,338
Other		144,837			154,593
Accrued taxes		122,734			79,766
Other		239,984			248,439
		4,493,773			4,244,857
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 750 shares,
7 shares outstanding		1,462,133			1,464,229
Accumulated other comprehensive loss		(84,473	)		(91,871	)
Retained earnings		1,742,746			1,572,065
Total common stockholder's equity		3,120,406			2,944,423
Long-term debt and other long-term obligations		670,061			571,448
		3,790,467			3,515,871
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		1,018,156			1,026,584
Accumulated deferred investment tax credits		61,645			62,728
Asset retirement obligations		877,073			863,085
Retirement benefits		198,803			194,177
Property taxes		50,104			50,104
Lease market valuation liability		296,376			307,705
Other		86,630			89,910
		2,588,787			2,594,293
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	10,873,027		$	10,355,021

The accompanying Notes to Consolidated Financial Statements as they relate 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
	2009			2008
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	170,681		$	89,984
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		61,373			49,742
Nuclear fuel and lease amortization		27,169			25,426
Deferred rents and lease market valuation liability		(37,522	)		(34,887	)
Deferred income taxes and investment tax credits, net		24,866			30,781
Investment impairment		33,535			14,943
Accrued compensation and retirement benefits		(3,439	)		(11,042	)
Commodity derivative transactions, net		15,817			8,086
Gain on asset sales		(5,209	)		(4,964	)
Cash collateral, net		(5,492	)		1,601
Decrease (increase) in operating assets:
Receivables		80,067			69,533
Materials and supplies		(865	)		(12,948	)
Prepayments and other current assets		(3,456	)		(12,260	)
Increase (decrease) in operating liabilities:
Accounts payable		(61,419	)		(17,149	)
Accrued taxes		39,846			(28,652	)
Accrued interest		10,338			(728	)
Other		1,577			(7,514	)
Net cash provided from operating activities		347,867			159,952

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		100,000			-
Short-term borrowings, net		621,294			1,281,896
Redemptions and Repayments-
Long-term debt		(335,916	)		(288,603	)
Common stock dividend payments		-			(10,000	)
Net cash provided from financing activities		385,378			983,293

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(412,805	)		(476,529	)
Proceeds from asset sales		7,573			5,088
Sales of investment securities held in trusts		351,414			173,123
Purchases of investment securities held in trusts		(356,904	)		(181,079	)
Loans to associated companies, net		(303,963	)		(644,604	)
Other		(18,565	)		(19,244	)
Net cash used for investing activities		(733,250	)		(1,143,245	)

Net change in cash and cash equivalents		(5	)		-
Cash and cash equivalents at beginning of period		39			2
Cash and cash equivalents at end of period	$	34		$	2

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

OHIO EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They provide generation services to those franchise customers electing to retain OE and Penn as their power supplier. Until December 31, 2008, OE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that reflected the rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond.

Results of Operations

In the first three months of 2009, net income decreased to $12 million from $44 million in the same period of 2008. The decrease primarily resulted from the completion of the recovery of transition costs at the end of 2008 and accrued obligations principally associated with the implementation of the ESP in 2009. OE’s financial statements include certain immaterial adjustments that relate to prior periods that reduced net income by $3 million for the first quarter of 2009.

Revenues

Revenues increased by $96 million, or 14.8%, in the first three months of 2009 compared with the same period in 2008, primarily due to increases in retail generation revenues ($114 million) and wholesale revenues ($35 million), partially offset by decreases in distribution throughput revenues ($53 million).

Retail generation revenues increased primarily due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers, reflecting a decrease in customer shopping for those sectors as most of OE’s franchise customers returned to PLR service in December 2008. Reduced industrial KWH sales reflected weakened economic conditions in OE’s and Penn’s service territories. Additional generation revenues from OE’s fuel rider effective in January 2009 contributed to the rate variances (see Regulatory Matters – Ohio).

Changes in retail generation sales and revenues in the first three months of 2009 from the same period in 2008 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)

Residential		11.8	%
Commercial		17.3	%
Industrial		(8.2	)%
Net Increase in Generation Sales		7.2	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	55
Commercial		41
Industrial		18
Increase in Generation Revenues	$	114

Revenues from distribution throughput decreased by $53 million in the first three months of 2009 compared to the same period in 2008 due to lower average unit prices and lower KWH deliveries to all customer classes. Reduced deliveries to commercial and industrial customers were a result of the weakened economy. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a July 2008 increase to a PUCO-approved transmission rider and a January 2009 distribution rate increase (see Regulatory Matters – Ohio).

Changes in distribution KWH deliveries and revenues in the first three months of 2009 from the same period in 2008 are summarized in the following tables.

Distribution KWH Deliveries	Decrease

Residential		(1.0	)%
Commercial		(4.7	)%
Industrial		(22.9	)%
Decrease in Distribution Deliveries		(9.2	)%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(8	)
Commercial		(22	)
Industrial		(23	)
Decrease in Distribution Revenues	$	(53	)

Expenses

Total expenses increased by $143 million in the first three months of 2009 from the same period of 2008. The following table presents changes from the prior year by expense category.

Expenses – Changes	Increase (Decrease)
		(In millions)
Purchased power costs	$	130
Other operating costs		17
Amortization of regulatory assets, net		(3	)
General taxes		(1	)
Net Increase in Expenses	$	143

Higher purchased power costs are primarily due to the results of the CBP used for the procurement of electric generation for retail customers during the first quarter of 2009 and higher volumes due to increased retail generation KWH sales. The increase in other operating costs for the first three months of 2009 was primarily due to accruals for economic development programs, in accordance with the PUCO-approved ESP, and energy efficiency obligations. Lower amortization of net regulatory assets was primarily due to the conclusion of transition cost amortization in 2008, partially offset by lower MISO transmission cost deferrals and lower RCP distribution deferrals.

Other Expenses

Other expenses increased by $8 million in the first three months of 2009 compared to the same period in 2008 primarily due to higher interest expense associated with the issuance of OE’s $300 million of FMBs in October 2008.

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, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 6 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 7, 2009

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	720,011		$	622,271
Excise and gross receipts tax collections		28,980			30,378
Total revenues		748,991			652,649

EXPENSES:
Purchased power from affiliates		332,336			319,711
Purchased power from non-affiliates		137,813			20,475
Other operating costs		157,830			140,326
Provision for depreciation		21,513			21,493
Amortization of regulatory assets, net		20,211			23,127
General taxes		49,120			50,453
Total expenses		718,823			575,585

OPERATING INCOME		30,168			77,064

OTHER INCOME (EXPENSE):
Investment income		9,362			15,055
Miscellaneous expense		(810	)		(3,652	)
Interest expense		(23,287	)		(17,641	)
Capitalized interest		220			110
Total other expense		(14,515	)		(6,128	)

INCOME BEFORE INCOME TAXES		15,653			70,936

INCOME TAXES		4,005			26,873

NET INCOME		11,648			44,063

Less: Noncontrolling interest income		146			154

EARNINGS AVAILABLE TO PARENT	$	11,502		$	43,909

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	11,648		$	44,063

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		5,738			(3,994	)
Change in unrealized gain on available-for-sale securities		(2,709	)		(7,571	)
Other comprehensive income (loss)		3,029			(11,565	)
Income tax expense (benefit) related to other comprehensive income		529			(4,262	)
Other comprehensive income (loss), net of tax		2,500			(7,303	)

COMPREHENSIVE INCOME		14,148			36,760

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		146			154

COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT	$	14,002		$	36,606

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,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	311,192		$	146,343
Receivables-
Customers (less accumulated provisions of $6,621,000 and $6,065,000, respectively,
for uncollectible accounts)		292,159			277,377
Associated companies		217,455			234,960
Other (less accumulated provisions of $8,000 and $7,000, respectively,
for uncollectible accounts)		19,492			14,492
Notes receivable from associated companies		77,264			222,861
Prepayments and other		22,544			5,452
		940,106			901,485
UTILITY PLANT:
In service		2,915,643			2,903,290
Less - Accumulated provision for depreciation		1,120,219			1,113,357
		1,795,424			1,789,933
Construction work in progress		47,022			37,766
		1,842,446			1,827,699
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		256,473			256,974
Investment in lease obligation bonds		239,501			239,625
Nuclear plant decommissioning trusts		112,778			116,682
Other		98,729			100,792
		707,481			714,073
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		544,782			575,076
Property taxes		60,542			60,542
Unamortized sale and leaseback costs		38,880			40,130
Other		32,418			33,710
		676,622			709,458
	$	4,166,655		$	4,152,715
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	2,697		$	101,354
Short-term borrowings-
Associated companies		79,810			-
Other		1,540			1,540
Accounts payable-
Associated companies		115,778			131,725
Other		54,237			26,410
Accrued taxes		72,736			77,592
Accrued interest		23,717			25,673
Other		124,871			85,209
		475,386			449,503
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 shares outstanding		1,224,347			1,224,416
Accumulated other comprehensive loss		(181,885	)		(184,385	)
Retained earnings		265,525			254,023
Total common stockholder's equity		1,307,987			1,294,054
Noncontrolling interest		7,252			7,106
Total equity		1,315,239			1,301,160
Long-term debt and other long-term obligations		1,123,966			1,122,247
		2,439,205			2,423,407
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		650,601			653,475
Accumulated deferred investment tax credits		12,700			13,065
Asset retirement obligations		81,944			80,647
Retirement benefits		305,943			308,450
Other		200,876			224,168
		1,252,064			1,279,805
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	4,166,655		$	4,152,715

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
	2009			2008
	In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	11,648		$	44,063
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		21,513			21,493
Amortization of regulatory assets, net		20,211			23,127
Purchased power cost recovery reconciliation		2,978			-
Amortization of lease costs		32,934			32,934
Deferred income taxes and investment tax credits, net		(7,272	)		6,866
Accrued compensation and retirement benefits		(1,746	)		(19,482	)
Accrued regulatory obligations		18,350			-
Electric service prepayment programs		(3,944	)		(10,028	)
Decrease (increase) in operating assets-
Receivables		1,435			(27,496	)
Prepayments and other current assets		(9,806	)		(7,451	)
Increase (decrease) in operating liabilities-
Accounts payable		11,880			(3,939	)
Accrued taxes		(26,222	)		2,991
Accrued interest		(1,956	)		(5,919	)
Other		6,708			(2,220	)
Net cash provided from operating activities		76,711			54,939

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		79,810			-
Redemptions and Repayments-
Long-term debt		(100,393	)		(75	)
Dividend Payments-
Common stock		-			(15,000	)
Other		(69	)		(5	)
Net cash used for financing activities		(20,652	)		(15,080	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(37,523	)		(49,011	)
Sales of investment securities held in trusts		9,417			62,344
Purchases of investment securities held in trusts		(10,422	)		(63,797	)
Loan repayments from associated companies, net		146,098			6,534
Cash investments		(243	)		147
Other		1,463			3,924
Net cash provided from (used for) investing activities		108,790			(39,859	)

Net change in cash and cash equivalents		164,849			-
Cash and cash equivalents at beginning of period		146,343			732
Cash and cash equivalents at end of period	$	311,192		$	732

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

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. Until December 31, 2008, CEI purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond.

Results of Operations

CEI recognized a net loss of $105 million in the first three months of 2009 compared to net income of $58 million in the same period of 2008. The decrease resulted primarily from CEI’s $216 million regulatory asset impairment related to the implementation of its ESP and increased purchased power costs, partially offset by higher deferrals of new regulatory assets.

Revenues

Revenues increased by $12 million, or 2.8%, in the first three months of 2009 compared to the same period of 2008 primarily due to an increase in retail generation revenues ($18 million), partially offset by decreases in distribution revenues ($4 million) and other miscellaneous revenues ($2 million).

Retail generation revenues increased in the first three months of 2009 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 2008. Generation rate increases under CEI’s CBP contributed to the increased rate variances (see Regulatory Matters – Ohio). Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions. The increase in sales volume for residential and commercial customers primarily reflected a decrease in customer shopping, as most of CEI’s customers returned to PLR service in December 2008.

Changes in retail generation sales and revenues in the first three months of 2009 compared to the same period in 2008 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)
Residential		8.0	%
Commercial		12.5	%
Industrial		(9.8	)%
Net Increase in Retail Generation Sales		1.4	%

Retail Generation Revenues	Increase (Decrease)
	(in millions)
Residential	$	8
Commercial		12
Industrial		(2	)
Net Increase in Generation Revenues	$	18

Revenues from distribution throughput decreased by $4 million in the first three months of 2009 compared to the same period of 2008 primarily due lower KWH deliveries to commercial and industrial customers as a result of the economic downturn in CEI’s service territory.

Decreases in distribution KWH deliveries and revenues in the first three months of 2009 compared to the same period of 2008 are summarized in the following tables.

Distribution KWH Deliveries	Decrease
Residential		(0.6	)%
Commercial		(5.1	)%
Industrial		(19.8	)%
Decrease in Distribution Deliveries		(10.0	)%

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

Expenses

Total expenses increased by $267 million in the first three months of 2009 compared to the same period of 2008. The following table presents the change from the prior year by expense category:

Expenses - Changes	Increase (Decrease)
	(in millions)
Purchased power costs	$	117
Amortization of regulatory assets		218
Deferral of new regulatory assets		(66	)
General taxes		(2	)
Net Increase in Expenses	$	267

Higher purchased power costs are primarily due to the results of the CBP used for the procurement of electric generation for retail customers in the first quarter of 2009. Increased amortization of regulatory assets was primarily due to the impairment of CEI’s Extended RTC balance in accordance with the PUCO-approved ESP. The increase in the deferral of new regulatory assets was primarily due to CEI’s deferral of purchased power costs as approved by the PUCO, partially offset by lower deferred MISO transmission expenses and the absence of RCP distribution deferrals that ceased at the end of 2008. While other operating costs were unchanged from the previous year, cost increases associated with the ESP for economic development and energy efficiency programs, higher pension expense and restructuring costs were completely offset by reduced transmission expense, labor, contractor costs and general business expense. The decrease in general taxes is primarily due to lower property taxes.

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, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 6 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 7, 2009

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	431,405		$	418,708
Excise tax collections		18,320			18,600
Total revenues		449,725			437,308

EXPENSES:
Purchased power from affiliates		238,872			190,196
Purchased power from non-affiliates		71,746			3,048
Other operating costs		64,830			65,118
Provision for depreciation		18,280			19,076
Amortization of regulatory assets		256,737			38,256
Deferral of new regulatory assets		(94,816	)		(29,248	)
General taxes		38,141			40,083
Total expenses		593,790			326,529

OPERATING INCOME (LOSS)		(144,065	)		110,779

OTHER INCOME (EXPENSE):
Investment income		8,420			9,188
Miscellaneous income		1,994			1,118
Interest expense		(33,322	)		(32,520	)
Capitalized interest		67			196
Total other expense		(22,841	)		(22,018	)

INCOME (LOSS) BEFORE INCOME TAXES		(166,906	)		88,761

INCOME TAX EXPENSE (BENEFIT)		(61,506	)		30,326

NET INCOME (LOSS)		(105,400	)		58,435

Less: Noncontrolling interest income		458			584

EARNINGS (LOSS) AVAILABLE TO PARENT	$	(105,858	)	$	57,851

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME (LOSS)	$	(105,400	)	$	58,435

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		3,967			(213	)
Income tax expense related to other comprehensive income		1,370			281
Other comprehensive income (loss), net of tax		2,597			(494	)

COMPREHENSIVE INCOME (LOSS)		(102,803	)		57,941

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		458			584

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO PARENT	$	(103,261	)	$	57,357

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,
		2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	233		$	226
Receivables-
Customers (less accumulated provisions of $6,199,000 and
$5,916,000, respectively, for uncollectible accounts)			283,967			276,400
Associated companies			159,819			113,182
Other			4,438			13,834
Notes receivable from associated companies			22,744			19,060
Prepayments and other			2,002			2,787
			473,203			425,489
UTILITY PLANT:
In service			2,240,065			2,221,660
Less - Accumulated provision for depreciation			852,393			846,233
			1,387,672			1,375,427
Construction work in progress			40,545			40,651
			1,428,217			1,416,078
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			388,647			425,715
Other			10,239			10,249
			398,886			435,964
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			1,688,521			1,688,521
Regulatory assets			617,967			783,964
Property taxes			71,500			71,500
Other			10,629			10,818
			2,388,617			2,554,803
		$	4,688,923		$	4,832,334
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	150,704		$	150,688
Short-term borrowings-
Associated companies			242,065			227,949
Accounts payable-
Associated companies			94,824			106,074
Other			26,914			7,195
Accrued taxes			76,130			87,810
Accrued interest			41,546			13,932
Other			44,021			40,095
			676,204			633,743
CAPITALIZATION:
Common stockholder's equity
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding			878,680			878,785
Accumulated other comprehensive loss			(132,260	)		(134,857	)
Retained earnings			754,096			859,954
Total common stockholder's equity			1,500,516			1,603,882
Noncontrolling interest			20,173			22,555
Total equity			1,520,689			1,626,437
Long-term debt and other long-term obligations			1,573,241			1,591,586
			3,093,930			3,218,023
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			644,547			704,270
Accumulated deferred investment tax credits			12,731			13,030
Retirement benefits			129,537			128,738
Lease assignment payable to associated companies			40,827			40,827
Other			91,147			93,703
			918,789			980,568
COMMITMENTS AND CONTINGENCIES (Note 8)
		$	4,688,923		$	4,832,334


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

	2009			2008

	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(105,400	)	$	58,435
Adjustments to reconcile net income (loss) to net cash from operating activities-
Provision for depreciation		18,280			19,076
Amortization of regulatory assets		256,737			38,256
Deferral of new regulatory assets		(94,816	)		(29,248	)
Deferred income taxes and investment tax credits, net		(61,525	)		(4,965	)
Accrued compensation and retirement benefits		1,828			(3,507	)
Accrued regulatory obligations		12,057			-
Electric service prepayment programs		(2,695	)		(5,847	)
Decrease (increase) in operating assets-
Receivables		(44,808	)		90,280
Prepayments and other current assets		785			604
Increase (decrease) in operating liabilities-
Accounts payable		18,470			1,111
Accrued taxes		(16,274	)		23,196
Accrued interest		27,614			23,831
Other		346			2,308
Net cash provided from operating activities		10,599			213,530

CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt		(181	)		(165	)
Short-term borrowings, net		(4,086	)		(177,960	)
Dividend Payments-
Common stock		(10,000	)		(30,000	)
Other		(2,840	)		(2,955	)
Net cash used for financing activities		(17,107	)		(211,080	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(24,900	)		(37,203	)
Loans to associated companies, net		(3,683	)		(2,373	)
Redemptions of lessor notes		37,068			37,709
Other		(1,970	)		(574	)
Net cash provided from (used for) investing activities		6,515			(2,441	)

Net increase in cash and cash equivalents		7			9
Cash and cash equivalents at beginning of period		226			232
Cash and cash equivalents at end of period	$	233		$	241


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

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. Until December 31, 2008, TE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond.

Results of Operations

Net income in the first three months of 2009 decreased to $1 million from $17 million in the same period of 2008. The decrease resulted primarily from the completion of transition cost recovery in 2008.

Revenues

Revenues increased $33 million, or 15.6%, in the first three months of 2009 compared to the same period of 2008 primarily due to increased retail generation revenues ($67 million), partially offset by lower distribution revenues ($33 million) and wholesale generation revenues ($1 million).

Retail generation revenues increased in the first three months of 2009 due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers, compared to the same period of 2008. TE’s implementation of a fuel rider in January 2009 produced the rate variances (see Regulatory Matters – Ohio). Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions. The increase in sales volume for residential and commercial customers resulted principally from a decrease in customer shopping. Most of TE’s franchise customers returned to PLR service in December 2008.

Changes in retail electric generation KWH sales and revenues in the first three months of 2009 from the same period of 2008 are summarized in the following tables.

	Increase
Retail KWH Sales	(Decrease)

Residential		6.5	%
Commercial		39.3	%
Industrial		(11.5	)%
Net Increase in Retail KWH Sales		3.9	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	16
Commercial		26
Industrial		25
Increase in Retail Generation Revenues	$	67

Revenues from distribution throughput decreased by $33 million in the first three months of 2009 compared to the same period in 2008 due to lower average unit prices and lower KWH deliveries for all customer classes. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a PUCO-approved distribution rate increase (see Regulatory Matters – Ohio).

Changes in distribution KWH deliveries and revenues in the first three months of 2009 from the same period of 2008 are summarized in the following tables.

Distribution KWH Deliveries	Decrease

Residential		(2.8	)%
Commercial		(10.0	)%
Industrial		(13.5	)%
Decrease in Distribution Deliveries		(9.6	)%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(8	)
Commercial		(17	)
Industrial		(8	)
Decrease in Distribution Revenues	$	(33	)

Expenses

Total expenses increased $57 million in the first three months of 2009 from the same period of 2008. The following table presents changes from the prior year by expense category.

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	64
Provision for depreciation		(1	)
Amortization of regulatory assets, net		(6	)
Net Increase in Expenses	$	57

Higher purchased power costs are primarily due to the results of the CBP used for the procurement of electric generation for retail customers during the first quarter of 2009. While other operating costs were unchanged from the first quarter of 2008, cost increases associated with the regulatory obligations for economic development and energy efficiency programs, higher pension and other expenses were completely offset by reduced transmission, labor and other employee benefit expenses. Depreciation expense decreased due to the transfer of leasehold improvements for the Bruce Mansfield Plant and Beaver Valley Unit 2 to FGCO and NGC, respectively, during 2008. The decrease in the net amortization of regulatory assets is primarily due to the cessation of transition cost amortization, partially offset by a reduction in transmission deferrals and the absence of RCP distribution cost deferrals in 2009.

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, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 6 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 7, 2009

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	237,085		$	203,669
Excise tax collections		7,729			8,025
Total revenues		244,814			211,694

EXPENSES:
Purchased power from affiliates		125,324			99,494
Purchased power from non-affiliates		40,537			1,804
Other operating costs		45,004			45,329
Provision for depreciation		7,572			9,025
Amortization of regulatory assets, net		9,897			15,531
General taxes		14,250			14,377
Total expenses		242,584			185,560

OPERATING INCOME		2,230			26,134

OTHER INCOME (EXPENSE):
Investment income		5,484			6,481
Miscellaneous expense		(1,340	)		(1,512	)
Interest expense		(5,533	)		(6,035	)
Capitalized interest		42			37
Total other expense		(1,347	)		(1,029	)

INCOME BEFORE INCOME TAXES		883			25,105

INCOME TAX EXPENSE (BENEFIT)		(109	)		8,088

NET INCOME		992			17,017

Less: Noncontrolling interest income		2			2

EARNINGS AVAILABLE TO PARENT	$	990		$	17,015

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	992		$	17,017

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		133			(63	)
Change in unrealized gain on available-for-sale securities		(809	)		1,961
Other comprehensive income (loss)		(676	)		1,898
Income tax expense (benefit) related to other comprehensive income		(19	)		728
Other comprehensive income (loss), net of tax		(657	)		1,170

COMPREHENSIVE INCOME		335			18,187

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		2			2

COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT	$	333		$	18,185

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

THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,				December 31,
		2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	15		$	14
Receivables-
Customers			438			751
Associated companies			70,444			61,854
Other (less accumulated provisions of $193,000 and $203,000,
respectively, for uncollectible accounts)			23,693			23,336
Notes receivable from associated companies			133,186			111,579
Prepayments and other			4,481			1,213
			232,257			198,747
UTILITY PLANT:
In service			880,315			870,911
Less - Accumulated provision for depreciation			413,030			407,859
			467,285			463,052
Construction work in progress			10,957			9,007
			478,242			472,059
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			124,329			142,687
Long-term notes receivable from associated companies			37,154			37,233
Nuclear plant decommissioning trusts			73,235			73,500
Other			1,646			1,668
			236,364			255,088
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			500,576			500,576
Regulatory assets			96,351			109,364
Property taxes			22,970			22,970
Other			62,004			51,315
			681,901			684,225
		$	1,628,764		$	1,610,119
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	222		$	34
Accounts payable-
Associated companies			59,462			70,455
Other			14,823			4,812
Notes payable to associated companies			107,265			111,242
Accrued taxes			23,259			24,433
Lease market valuation liability			36,900			36,900
Other			54,397			22,489
			296,328			270,365
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			175,866			175,879
Accumulated other comprehensive loss			(34,029	)		(33,372	)
Retained earnings			191,523			190,533
Total common stockholder's equity			480,370			480,050
Noncontrolling interest			2,676			2,675
Total equity			483,046			482,725
Long-term debt and other long-term obligations			303,021			299,626
			786,067			782,351
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			77,016			78,905
Accumulated deferred investment tax credits			6,695			6,804
Lease market valuation liability			263,875			273,100
Retirement benefits			74,911			73,106
Asset retirement obligations			30,719			30,213
Lease assignment payable to associated companies			30,529			30,529
Other			62,624			64,746
			546,369			557,403
COMMITMENTS AND CONTINGENCIES (Note 8)
		$	1,628,764		$	1,610,119

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

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	992		$	17,017
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		7,572			9,025
Amortization of regulatory assets, net		9,897			15,531
Purchased power cost recovery reconciliation		2,912			-
Deferred rents and lease market valuation liability		6,141			6,099
Deferred income taxes and investment tax credits, net		(2,151	)		(3,404	)
Accrued compensation and retirement benefits		397			(1,813	)
Accrued regulatory obligations		4,450			-
Electric service prepayment programs		(1,240	)		(2,670	)
Decrease (increase) in operating assets-
Receivables		(8,395	)		45,738
Prepayments and other current assets		492			181
Increase (decrease) in operating liabilities-
Accounts payable		9,018			(174,243	)
Accrued taxes		(4,904	)		6,840
Accrued interest		4,613			4,663
Other		1,465			989
Net cash provided from (used for) operating activities		31,259			(76,047	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		-			52,821
Redemptions and Repayments-
Long-term debt		(181	)		(9	)
Short-term borrowings, net		(3,977	)		-
Dividend Payments-
Common stock		(10,000	)		(15,000	)
Other		(39	)		-
Net cash provided from (used for) financing activities		(14,197	)		37,812

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(12,233	)		(19,435	)
Loan repayments from (loans to) associated companies, net		(21,528	)		46,789
Redemption of lessor notes		18,358			11,989
Sales of investment securities held in trusts		44,270			3,908
Purchases of investment securities held in trusts		(44,856	)		(4,715	)
Other		(1,072	)		(110	)
Net cash provided from (used for) investing activities		(17,061	)		38,426

Net change in cash and cash equivalents		1			191
Cash and cash equivalents at beginning of period		14			22
Cash and cash equivalents at end of period	$	15		$	213

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

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 franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.

Results of Operations

Net income for the first three months of 2009 decreased to $28 million from $34 million in the same period in 2008. The decrease was primarily due to lower revenues and higher other operating costs, partially offset by lower purchased power costs and reduced amortization of regulatory assets.

Revenues

In the first three months of 2009, revenues decreased by $21 million, or 3%, compared to the same period of 2008. A $31 million increase in retail generation revenues was more than offset by a $47 million decrease in wholesale revenues in the first three months of 2009.

Retail generation revenues from all customer classes increased in the first three months of 2009 compared to the same period of 2008 due to higher unit prices resulting from the BGS auction effective June 1, 2008, partially offset by a decrease in retail generation KWH sales to commercial customers. Sales volume to the commercial sector decreased primarily due to an increase in the number of customers procuring generation from other suppliers.

Wholesale generation revenues decreased $47 million in the first three months of 2009 due to lower market prices and a decrease in sales volume (from NUG purchases) as compared to the first three months of 2008.

Changes in retail generation KWH sales and revenues by customer class in the first three months of 2009 compared to the same period of 2008 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)

Residential		0.1	%
Commercial		(7.0	)%
Industrial		2.9	%
Net Decrease in Generation Sales		(2.7	)%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	30
Commercial		1
Industrial		-
Increase in Generation Revenues	$	31

Distribution revenues decreased by $1 million in the first three months of 2009 compared to the same period of 2008, reflecting lower KWH deliveries to commercial and industrial customers as a result of weakened economic conditions in JCP&L’s service territory. The decrease in KWH deliveries was partially offset by an increase in composite unit prices.

Changes in distribution KWH deliveries and revenues by customer class in the first three months of 2009 compared to the same period in 2008 are summarized in the following tables:

	Increase
Distribution KWH Deliveries	(Decrease)

Residential		-	%
Commercial		(2.4	)%
Industrial		(11.4	)%
Decrease in Distribution Deliveries		(2.5	)%

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

Expenses

Total expenses decreased by $11 million in the first three months of 2009 compared to the same period of 2008. The following table presents changes from the prior year period by expense category:

Expenses - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	(15	)
Other operating costs		7
Provision for depreciation		2
Amortization of regulatory assets		(5	)
Net Decrease in Expenses	$	(11	)

Purchased power costs decreased in the first three months of 2009 primarily due to lower KWH purchases to meet the lower demand, partially offset by higher unit prices from the BGS auction effective June 1, 2008. Other operating costs increased in the first three months of 2009 primarily due to higher expenses related to employee benefits and customer assistance programs, partially offset by lower contracting and labor expenses. Depreciation expense increased primarily due to an increase in depreciable property since the first quarter of 2008. Amortization of regulatory assets decreased in the first three months of 2009 primarily due to the full recovery of certain regulatory assets in June 2008.

Other Expenses

Other expenses increased by $2 million in the first three months of 2009 compared to the same period in 2008 primarily due to interest expense associated with JCP&L’s $300 million Senior Notes issuance in January 2009.

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, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, 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, 2008, 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, 2009

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)

REVENUES:
Electric sales	$	760,920		$	781,433
Excise tax collections		12,731			12,795
Total revenues		773,651			794,228

EXPENSES:
Purchased power		481,241			496,681
Other operating costs		85,870			78,784
Provision for depreciation		25,103			23,282
Amortization of regulatory assets		86,831			91,519
General taxes		17,496			17,028
Total expenses		696,541			707,294

OPERATING INCOME		77,110			86,934

OTHER INCOME (EXPENSE):
Miscellaneous income (expense)		805			(389	)
Interest expense		(27,868	)		(24,464	)
Capitalized interest		62			276
Total other expense		(27,001	)		(24,577	)

INCOME BEFORE INCOME TAXES		50,109			62,357

INCOME TAXES		22,551			28,403

NET INCOME		27,558			33,954

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		4,121			(3,449	)
Unrealized gain on derivative hedges		69			69
Other comprehensive income (loss)		4,190			(3,380	)
Income tax expense (benefit) related to other comprehensive income		1,430			(1,470	)
Other comprehensive income (loss), net of tax		2,760			(1,910	)

TOTAL COMPREHENSIVE INCOME	$	30,318		$	32,044

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,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4		$	66
Receivables-
Customers (less accumulated provisions of $3,415,000 and $3,230,000
respectively, for uncollectible accounts)		315,084			340,485
Associated companies		116			265
Other		35,941			37,534
Notes receivable - associated companies		91,362			16,254
Prepaid taxes		4,243			10,492
Other		21,006			18,066
		467,756			423,162
UTILITY PLANT:
In service		4,337,711			4,307,556
Less - Accumulated provision for depreciation		1,562,417			1,551,290
		2,775,294			2,756,266
Construction work in progress		69,806			77,317
		2,845,100			2,833,583
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		189,784			181,468
Nuclear plant decommissioning trusts		136,783			143,027
Other		2,154			2,145
		328,721			326,640
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,810,936			1,810,936
Regulatory assets		1,162,132			1,228,061
Other		28,487			29,946
		3,001,555			3,068,943
	$	6,643,132		$	6,652,328
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	29,465		$	29,094
Short-term borrowings-
Associated companies		-			121,380
Accounts payable-
Associated companies		22,562			12,821
Other		158,972			198,742
Accrued taxes		53,998			20,561
Accrued interest		30,446			9,197
Other		129,745			133,091
		425,188			524,886
CAPITALIZATION
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares-
13,628,447 shares outstanding		136,284			144,216
Other paid-in capital		2,502,594			2,644,756
Accumulated other comprehensive loss		(213,778	)		(216,538	)
Retained earnings		121,134			156,576
Total common stockholder's equity		2,546,234			2,729,010
Long-term debt and other long-term obligations		1,824,851			1,531,840
		4,371,085			4,260,850
NONCURRENT LIABILITIES:
Power purchase contract liability		530,538			531,686
Accumulated deferred income taxes		664,388			689,065
Nuclear fuel disposal costs		196,260			196,235
Asset retirement obligations		96,839			95,216
Retirement benefits		185,265			190,182
Other		173,569			164,208
		1,846,859			1,866,592
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	6,643,132		$	6,652,328

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

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	27,558		$	33,954
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		25,103			23,282
Amortization of regulatory assets		86,831			91,519
Deferred purchased power and other costs		(28,369	)		(23,893	)
Deferred income taxes and investment tax credits, net		(6,408	)		723
Accrued compensation and retirement benefits		(7,481	)		(15,113	)
Cash collateral returned to suppliers		(209	)		(502	)
Decrease (increase) in operating assets:
Receivables		27,143			48,733
Materials and supplies		-			255
Prepaid taxes		6,249			(290	)
Other current assets		(1,457	)		(1,305	)
Increase (decrease) in operating liabilities:
Accounts payable		(30,029	)		(14,511	)
Accrued taxes		33,114			29,844
Accrued interest		21,249			17,338
Other		7,890			(3,098	)
Net cash provided from operating activities		161,184			186,936

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		299,619			-
Redemptions and Repayments-
Common stock		(150,000	)		-
Long-term debt		(6,402	)		(5,872	)
Short-term borrowings, net		(121,380	)		(48,001	)
Dividend Payments-
Common stock		(63,000	)		(70,000	)
Other		(2,152	)		(68	)
Net cash used for financing activities		(43,315	)		(123,941	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(37,372	)		(56,047	)
Loan repayments from (loans to) associated companies, net		(75,108	)		18
Sales of investment securities held in trusts		115,483			56,506
Purchases of investment securities held in trusts		(120,062	)		(61,290	)
Other		(872	)		(2,236	)
Net cash used for investing activities		(117,931	)		(63,049	)

Net change in cash and cash equivalents		(62	)		(54	)
Cash and cash equivalents at beginning of period		66			94
Cash and cash equivalents at end of period	$	4		$	40

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. Met-Ed has a partial requirements wholesale power sales agreement with FES, to supply a portion of each of its default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty day written notice prior to the end of the calendar year.

Results of Operations

Net income decreased to $17 million in the first quarter of 2009, compared to $22 million in the same period of 2008. The decrease was primarily due to higher purchased power costs and lower deferrals of new regulatory assets, partially offset by higher revenues.

Revenues

Revenues increased by $29 million, or 7.3%, in the first quarter of 2009, compared to the same period of 2008, primarily due to higher distribution throughput revenues and wholesale generation revenues, partially offset by a decrease in retail generation revenues. Wholesale revenues increased by $8 million in the first quarter of 2009, compared to the same period of 2008, due to higher capacity prices for PJM market participants; wholesale KWH sales volume was lower in 2009.

In the first quarter of 2009, retail generation revenues decreased $5 million due to lower KWH sales to the commercial and industrial customer classes, partially offset by higher KWH sales to the residential customer class with a slight increase in composite unit prices in all customer classes. Higher KWH sales in the residential sector were due to increased weather- related usage, reflecting an 8.1% increase in heating degree days in the first quarter of 2009. Lower KWH sales to commercial and industrial customers were principally due to economic conditions in Met-Ed’s service territory.

Changes in retail generation sales and revenues in the first quarter of 2009 compared to the same period of 2008 are summarized in the following tables:

	Increase
Retail Generation KWH Sales	(Decrease)

Residential		2.9	%
Commercial		(2.5	)%
Industrial		(12.9	)%
Net Decrease in Retail Generation Sales		(2.9	)%

	Increase
Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	2
Commercial		(1	)
Industrial		(6	)
Net Decrease in Retail Generation Revenues	$	(5	)

In the first quarter of 2009, distribution throughput revenues increased $22 million primarily due to higher transmission rates, resulting from the annual update of Met-Ed’s TSC rider effective June 1, 2008. Decreased deliveries to commercial and industrial customers, reflecting the weakened economy, were partially offset by increased deliveries to residential customers as a result of the weather conditions described above.

Changes in distribution KWH deliveries and revenues in the first quarter of 2009 compared to the same period of 2008 are summarized in the following tables:

	Increase
Distribution KWH Deliveries	(Decrease)

Residential		2.9	%
Commercial		(2.5	)%
Industrial		(12.9	)%
Net Decrease in Distribution Deliveries		(2.9	)%

Distribution Revenues	Increase
	(In millions)
Residential	$	14
Commercial		5
Industrial		3
Increase in Distribution Revenues	$	22

PJM transmission revenues increased by $4 million in the first quarter of 2009 compared to the same period of 2008, primarily due to increased revenues related to Met-Ed’s Auction Revenue Rights and Financial Transmission Rights. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses increased by $37 million in the first quarter of 2009 compared to the same period of 2008. The following table presents changes from the prior year by expense category:

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	7
Other operating costs		(1	)
Provision for depreciation		1
Deferral of new regulatory assets		30
Net Increase in Expenses	$	37

Purchased power costs increased by $7 million in the first quarter of 2009, primarily due to higher composite unit prices partially offset by decreased KWH purchases due to lower generation sales requirements. The deferral of new regulatory assets decreased in the first quarter of 2009 primarily due to decreased transmission cost deferrals reflecting lower PJM transmission service expenses and the increased transmission revenues described above.

Other Expense

Other expense increased in the first quarter of 2009 primarily due to a decrease in interest deferred on regulatory assets, reflecting a lower regulatory asset base, and an increase in interest expense from Met-Ed’s $300 million Senior Notes issuance in January 2009.

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 subsidiary as of March 31, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, 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, 2008, 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, 2009

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)

REVENUES:
Electric sales	$	409,686		$	379,608
Gross receipts tax collections		19,983			20,718
Total revenues		429,669			400,326

EXPENSES:
Purchased power from affiliates		100,077			83,442
Purchased power from non-affiliates		123,911			133,540
Other operating costs		106,357			107,017
Provision for depreciation		12,139			11,112
Amortization of regulatory assets		35,432			35,575
Deferral of new regulatory assets		(7,841	)		(37,772	)
General taxes		21,935			21,781
Total expenses		392,010			354,695

OPERATING INCOME		37,659			45,631

OTHER INCOME (EXPENSE):
Interest income		3,186			5,479
Miscellaneous income (expense)		856			(309	)
Interest expense		(13,359	)		(11,672	)
Capitalized interest		15			(219	)
Total other expense		(9,302	)		(6,721	)

INCOME BEFORE INCOME TAXES		28,357			38,910

INCOME TAXES		11,735			16,675

NET INCOME		16,622			22,235

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		4,553			(2,233	)
Unrealized gain on derivative hedges		84			84
Other comprehensive income (loss)		4,637			(2,149	)
Income tax expense (benefit) related to other comprehensive income		1,793			(970	)
Other comprehensive income (loss), net of tax		2,844			(1,179	)

TOTAL COMPREHENSIVE INCOME	$	19,466		$	21,056

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

METROPOLITAN EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	127		$	144
Receivables-
Customers (less accumulated provisions of $3,867,000 and $3,616,000,
respectively, for uncollectible accounts)		161,613			159,975
Associated companies		27,349			17,034
Other		17,521			19,828
Notes receivable from associated companies		229,614			11,446
Prepaid taxes		57,115			6,121
Other		5,238			1,621
		498,577			216,169
UTILITY PLANT:
In service		2,093,792			2,065,847
Less - Accumulated provision for depreciation		784,064			779,692
		1,309,728			1,286,155
Construction work in progress		19,087			32,305
		1,328,815			1,318,460
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		217,476			226,139
Other		975			976
		218,451			227,115
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		416,499			416,499
Regulatory assets		489,680			412,994
Power purchase contract asset		248,762			300,141
Other		37,231			31,031
		1,192,172			1,160,665
	$	3,238,015		$	2,922,409
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	128,500		$	28,500
Short-term borrowings-
Associated companies		-			15,003
Other		250,000			250,000
Accounts payable-
Associated companies		29,764			28,707
Other		46,216			55,330
Accrued taxes		8,489			16,238
Accrued interest		11,557			6,755
Other		29,506			30,647
		504,032			431,180
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,500 shares outstanding		1,196,090			1,196,172
Accumulated other comprehensive loss		(138,140	)		(140,984	)
Accumulated deficit		(34,502	)		(51,124	)
Total common stockholder's equity		1,023,448			1,004,064
Long-term debt and other long-term obligations		713,782			513,752
		1,737,230			1,517,816
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		390,448			387,757
Accumulated deferred investment tax credits		7,653			7,767
Nuclear fuel disposal costs		44,334			44,328
Asset retirement obligations		171,561			170,999
Retirement benefits		144,459			145,218
Power purchase contract liability		172,520			150,324
Other		65,778			67,020
		996,753			973,413
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	3,238,015		$	2,922,409

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
	2009			2008
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	16,622		$	22,235
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		12,139			11,112
Amortization of regulatory assets		35,432			35,575
Deferred costs recoverable as regulatory assets		(19,633	)		(10,628	)
Deferral of new regulatory assets		(7,841	)		(37,772	)
Deferred income taxes and investment tax credits, net		4,657			17,307
Accrued compensation and retirement benefits		1,029			(9,655	)
Cash collateral to suppliers		(9,500	)		-
Increase in operating assets-
Receivables		(9,860	)		(30,863	)
Prepayments and other current assets		(50,422	)		(41,088	)
Increase (decrease) in operating liabilities-
Accounts payable		(8,058	)		(14,196	)
Accrued taxes		(7,749	)		(14,519	)
Accrued interest		4,803			281
Other		2,460			3,892
Net cash used for operating activities		(35,921	)		(68,319	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		300,000			-
Short-term borrowings, net		-			131,743
Redemptions and Repayments-
Long-term debt		-			(28,500	)
Short-term borrowings, net		(15,003	)		-
Other		(2,150	)		(15	)
Net cash provided from financing activities		282,847			103,228

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(25,922	)		(31,296	)
Sales of investment securities held in trusts		27,800			40,513
Purchases of investment securities held in trusts		(29,821	)		(43,391	)
Loans to associated companies, net		(218,168	)		(254	)
Other		(832	)		(484	)
Net cash used for investing activities		(246,943	)		(34,912	)

Net change in cash and cash equivalents		(17	)		(3	)
Cash and cash equivalents at beginning of period		144			135
Cash and cash equivalents at end of period	$	127		$	132

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. Penelec has a partial requirements wholesale power sales agreement with FES, to supply a portion of each of its default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty day written notice prior to the end of the calendar year.

Results of Operations

Net income decreased to $19 million in the first quarter of 2009, compared to $21 million in the same period of 2008. The decrease was primarily due to lower revenues, partially offset by an increase in the deferral of new regulatory assets.

Revenues

Revenues decreased by $7 million, or 1.7%, in the first quarter of 2009 as compared to the same period of 2008, primarily due to lower retail generation revenues and PJM transmission revenues, partially offset by increased distribution throughput revenues and wholesale generation revenues. Wholesale generation revenues increased $7 million in the first quarter of 2009 as compared to the same period of 2008, primarily reflecting higher PJM capacity prices.

In the first quarter of 2009, retail generation revenues decreased $8 million primarily due to lower KWH sales to the commercial and industrial customer classes due to weakened economic conditions, partially offset by a slight increase in KWH sales to the residential customer class.

Changes in retail generation sales and revenues in the first quarter of 2009 compared to the same period of 2008 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)

Residential		0.4	%
Commercial		(3.2	) %
Industrial		(13.9	) %
Net Decrease in Retail Generation Sales		(4.9	) %

Retail Generation Revenues	Decrease
	(In millions)
Residential	$	-
Commercial		(2	)
Industrial		(6	)
Decrease in Retail Generation Revenues	$	(8	)

Revenues from distribution throughput increased $5 million in the first quarter of 2009 compared to the same period of 2008, primarily due to an increase in transmission rates, resulting from the annual update of Penelec’s TSC rider effective June 1, 2008, and a slight increase in usage in the residential sector. Partially offsetting this increase was lower usage in the commercial and industrial sectors, reflecting economic conditions in Penelec’s service territory.

Changes in distribution KWH deliveries and revenues in the first quarter of 2009 compared to the same period of 2008 are summarized in the following tables:

Distribution KWH Deliveries	Increase (Decrease)

Residential		0.4	%
Commercial		(3.2	) %
Industrial		(12.0	) %
Net Decrease in Distribution Deliveries		(4.6	) %

Distribution Revenues	Increase
	(In millions)
Residential	$	4
Commercial		1
Industrial		-
Increase in Distribution Revenues	$	5

PJM transmission revenues decreased by $13 million in the first quarter of 2009 compared to the same period of 2008, primarily due to lower revenues related to Penelec’s Financial Transmission Rights. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses increased by $5 million in the first quarter of 2009 as compared with the same period of 2008. The following table presents changes from the prior year by expense category:

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	2
Other operating costs		6
Provision for depreciation		2
Deferral of new regulatory assets		(4	)
General taxes		(1	)
Net Increase in Expenses	$	5

Purchased power costs increased by $2 million, or 0.9%, in the first quarter of 2009 compared to the same period of 2008, primarily due to increased composite unit prices, partially offset by reduced volume as a result of lower KWH sales requirements. Other operating costs increased by $6 million in the first quarter of 2009 primarily due to higher employee benefit expenses. Depreciation expense increased $2 million in the first quarter of 2009 primarily due to an increase in depreciable property in service since the first quarter of 2008. The deferral of new regulatory assets increased $4 million in the first quarter of 2009 primarily due to an increase in transmission cost deferrals as a result of increased net congestion costs.

Other Income

In the first quarter of 2009, other income increased primarily due to lower interest expense on reduced borrowings from the regulated money pool.

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, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, 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, 2008, 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, 2009

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)

REVENUES:
Electric sales	$	371,293		$	376,028
Gross receipts tax collections		17,292			19,464
Total revenues		388,585			395,492

EXPENSES:
Purchased power from affiliates		96,081			83,464
Purchased power from non-affiliates		127,166			137,770
Other operating costs		77,289			71,077
Provision for depreciation		14,455			12,516
Amortization of regulatory assets		16,141			16,346
Deferral of new regulatory assets		(7,365	)		(3,526	)
General taxes		20,593			21,855
Total expenses		344,360			339,502

OPERATING INCOME		44,225			55,990

OTHER INCOME (EXPENSE):
Miscellaneous income (expense)		798			(191	)
Interest expense		(13,233	)		(15,322	)
Capitalized interest		22			(806	)
Total other expense		(12,413	)		(16,319	)

INCOME BEFORE INCOME TAXES		31,812			39,671

INCOME TAXES		13,122			18,279

NET INCOME		18,690			21,392

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		2,955			(3,473	)
Unrealized gain on derivative hedges		16			16
Change in unrealized gain on available-for-sale securities		(22	)		11
Other comprehensive income (loss)		2,949			(3,446	)
Income tax expense (benefit) related to other comprehensive income		1,055			(1,506	)
Other comprehensive income (loss), net of tax		1,894			(1,940	)

TOTAL COMPREHENSIVE INCOME	$	20,584		$	19,452

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,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	13		$	23
Receivables-
Customers (less accumulated provisions of $3,285,000 and $3,121,000,
respectively, for uncollectible accounts)		140,783			146,831
Associated companies		80,387			65,610
Other		19,493			26,766
Notes receivable from associated companies		15,198			14,833
Prepaid taxes		66,392			16,310
Other		1,142			1,517
		323,408			271,890
UTILITY PLANT:
In service		2,345,475			2,324,879
Less - Accumulated provision for depreciation		873,677			868,639
		1,471,798			1,456,240
Construction work in progress		25,042			25,146
		1,496,840			1,481,386
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		113,265			115,292
Non-utility generation trusts		117,899			116,687
Other		289			293
		231,453			232,272
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		768,628			768,628
Power purchase contract asset		78,226			119,748
Other		15,308			18,658
		862,162			907,034
	$	2,913,863		$	2,892,582
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	145,000		$	145,000
Short-term borrowings-
Associated companies		112,034			31,402
Other		250,000			250,000
Accounts payable-
Associated companies		49,981			63,692
Other		42,004			48,633
Accrued taxes		4,053			13,264
Accrued interest		13,730			13,131
Other		26,591			31,730
		643,393			596,852
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		912,380			912,441
Accumulated other comprehensive loss		(126,103	)		(127,997	)
Retained earnings		94,803			76,113
Total common stockholder's equity		969,632			949,109
Long-term debt and other long-term obligations		633,355			633,132
		1,602,987			1,582,241
NONCURRENT LIABILITIES:
Regulatory liabilities		48,847			136,579
Accumulated deferred income taxes		183,906			169,807
Retirement benefits		172,544			172,718
Asset retirement obligations		87,395			87,089
Power purchase contract liability		112,462			83,600
Other		62,329			63,696
		667,483			713,489
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	2,913,863		$	2,892,582

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

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	18,690		$	21,392
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		14,455			12,516
Amortization of regulatory assets		16,141			16,346
Deferral of new regulatory assets		(7,365	)		(3,526	)
Deferred costs recoverable as regulatory assets		(20,022	)		(8,403	)
Deferred income taxes and investment tax credits, net		11,833			10,541
Accrued compensation and retirement benefits		431			(10,488	)
Cash collateral		-			301
Increase in operating assets-
Receivables		(1,709	)		(13,701	)
Prepayments and other current assets		(49,707	)		(40,591	)
Increase (Decrease) in operating liabilities-
Accounts payable		(5,340	)		(3,144	)
Accrued taxes		(9,065	)		(5,809	)
Accrued interest		599			510
Other		(988	)		4,991
Net cash used for operating activities		(32,047	)		(19,065	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		80,632			118,209
Redemptions and Repayments
Long-term debt		-			(45,112	)
Dividend Payments-
Common stock		(15,000	)		(20,000	)
Net cash provided from financing activities		65,632			53,097

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(28,190	)		(28,902	)
Sales of investment securities held in trusts		18,800			24,407
Purchases of investment securities held in trusts		(22,108	)		(29,083	)
Loan repayments to associated companies, net		(365	)		(610	)
Other		(1,732	)		153
Net cash used for investing activities		(33,595	)		(34,035	)

Net change in cash and cash equivalents		(10	)		(3	)
Cash and cash equivalents at beginning of period		23			46
Cash and cash equivalents at end of period	$	13		$	43

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 Utilities. This information should be read in conjunction with (i) FES’ and the Utilities’ 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 Utilities; and (iii) FES’ and the Utilities’ respective 2008 Annual Reports on Form 10-K.

Regulatory Matters (Applicable to each of the Utilities)

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

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

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

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

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

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

·	requiring corporate separation of regulated and unregulated business activities.

The Utilities 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 $130 million as of March 31, 2009 (JCP&L - $54 million and Met-Ed - $76 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*	2009		2008		(Decrease)
	(In millions)
OE	$	545	$	575	$	(30	)
CEI		618		784		(166	)
TE		96		109		(13	)
JCP&L		1,162		1,228		(66	)
Met-Ed		490		413		77
ATSI		27		31		(4	)
Total	$	2,938	$	3,140	$	(202	)

*	Penelec had net regulatory liabilities of approximately $49 million and $137 million as of March 31, 2009 and December 31, 2008, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

Ohio (Applicable to OE, CEI, TE and FES)

SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter. The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. In response to the PUCO’s December 19, 2008 order, which significantly modified and approved the ESP as modified, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application in addition to continuing their current rate plan in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. The average winning bid price was equivalent to a retail rate of 6.98 cents per kwh. The power supply obtained through this process provides generation service to the Ohio Companies’ retail customers who choose not to shop with alternative suppliers. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider to recover increased costs resulting from the CBP but did not authorize OE and TE to continue collecting RTC or allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider allows for current recovery of the increased purchased power costs for OE and TE, and authorizes CEI to collect a portion of those costs currently and defer the remainder for future recovery.

On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP provides that generation will be provided by FES at the average wholesale rate of the CBP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices will be based upon the outcome of a descending clock CBP on a slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of any increase resulting from this CBP process by authorizing deferral of related purchased power costs, subject to specified limits. The Amended ESP further provides that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI will agree to write-off approximately $216 million of its Extended RTC balance, and that the Ohio Companies will collect a delivery service improvement rider at an overall average rate of $.002 per kWh for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addresses a number of other issues, including but not limited to, rate design for various customer classes, resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation take effect on April 1, 2009 while the remaining provisions take effect on June 1, 2009. The CBP auction is currently scheduled to begin on May 13, 2009. The bidding will occur for a single, two-year product and there will not be a load cap for the bidders. FES may participate without limitation.

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

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

On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded and the companies are awaiting a Recommended Decision from the ALJ. The TSCs include a component from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.

On April 15, 2009, Met-Ed and Penelec filed revised TSCs with the PPUC for the period June 1, 2009 through May 31, 2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers, the new TSC would result in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers would increase to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, Met-Ed is proposing to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs into a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers would increase approximately 9.4% for the period June 2009 through May 2010.

On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. The bill addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters and alternative energy. Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. Similar guidelines related to Smart Meter deployment were issued for comment on March 30, 2009.

Major provisions of the legislation include:

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

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

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

·	~~SFAS 161~~a minimum reduction in peak demand of 4.5% by May 31, 2013;

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

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

Legislation addressing rate mitigation and the expiration of rate caps was not enacted in 2008; however, several bills addressing these issues have been introduced in the current legislative session, which began in January 2009. The final form and impact of such legislation is uncertain.

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

On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance Filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $51 million), overall rates would remain unchanged. The PPUC must act on this filing within 120 days.

New Jersey (Applicable to JCP&L)

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31, 2009, the accumulated deferred cost balance totaled approximately $165 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 DPA 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 March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.

The EMP was issued on October 22, 2008, establishing five major goals:

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

·	reduce peak demand for electricity by 5,700 MW by 2020;

·	meet 30% of the state’s electricity needs with renewable energy by 2020;

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

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

On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by December 31, 2009 by New Jersey electric and gas utilities in order to achieve the goals of the EMP. At this time, JCP&L cannot determine the impact, if any, the EMP may have on its operations.

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

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.

PJM Transmission Rate

The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce the costs of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.

Post Transition Period Rate Design

Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join MISO. Duquesne’s proposed move would affect numerous FirstEnergy interests, including but not limited to the terms under which FirstEnergy’s Beaver Valley Plant would continue to participate in PJM’s energy markets. FirstEnergy, therefore, intervened and participated fully in all of the FERC dockets that were related to Duquesne’s proposed move.

In November, 2008, Duquesne and other parties, including FirstEnergy, negotiated a settlement that would, among other things, allow for Duquesne to remain in PJM and provide for a methodology for Duquesne to meet the PJM capacity obligations for the 2011-2012 auction that excluded the Duquesne load. The settlement agreement was filed on December 10, 2008 and approved by the FERC in an order issued on January 29, 2009. MISO opposed the settlement agreement pending resolution of exit fees alleged to be owed by Duquesne. The FERC did not resolve the exit fee issue in its order. On March 2, 2009, the PPUC filed for rehearing of the FERC's January 29, 2009 order approving the settlement. Thereafter, FirstEnergy and other parties filed in opposition to the rehearing request. The PPUC's rehearing request, and the pleadings in opposition thereto, are pending before the FERC.

Changes ordered for PJM Reliability Pricing Model (RPM) Auction

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’ request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement talks. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.

MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load-serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load-serving entities in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.

On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process is expected to start as planned effective June 1, 2009, the beginning of the MISO planning year.

FES Sales to Affiliates

FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of the December 23, 2008 waiver.

Environmental Matters

Various federal, state and local authorities regulate FES and the Utilities with regard to air and water quality and other environmental matters. The effects of compliance on FES and the Utilities 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 Utilities 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 Utilities’ 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, OE, JCP&L, Met-Ed and Penelec)

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 $37,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FES 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 emission limits 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, the generation of more electricity at lower-emitting plants, and/or using emission allowances. 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.

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. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints. The Pennsylvania Department of Health and the U.S. Agency for Toxic Substance and Disease Registry recently disclosed their intention to conduct additional air monitoring in the vicinity of the Mansfield plant.

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), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. The future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

Mercury Emissions (Applicable to FES)

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, 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 petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. The EPA is developing new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

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

Climate Change (Applicable to FES)

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration had committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, former President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity in the United States comes from renewable sources by 2012, and increasing to 25% by 2025; and implementing an economy-wide cap-and-trade program to reduce GHG emissions 80% by 2050.

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

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 to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. FES is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

Regulation of Waste Disposal (Applicable to FES and each of the Utilities)

The Utilities have been named as potentially responsible parties 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 potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $91 million (JCP&L - - $64 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through March 31, 2009. Included in the total are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

Other Legal Proceedings

Power Outages and Related Litigation (Applicable to JCP&L)

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, the Muise class action) 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.

On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation requires JCP&L to respond to NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. JCP&L is not able at this time to predict what actions, if any, that NERC will take upon receipt of JCP&L’s response to NERC’s data request.

Nuclear Plant Matters (Applicable to FES)

In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.

Other Legal Matters (Applicable to FES and each of the Utilities)

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

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. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009; the appeal process could take as long as 24 months. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.

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. FES has a strike mitigation plan ready in the event of a strike.

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

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

FSP FAS 157-4 – “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”

In April 2009, the FASB issued Staff Position FAS 157-4, which provides additional guidance to consider in estimating fair value when there has been a significant decrease in market activity for a financial asset. The FSP establishes a two-step process requiring a reporting entity to first determine if a market is not active in relation to normal market activity for the asset. If evidence indicates the market is not active, an entity would then need to determine whether a quoted price in the market is associated with a distressed transaction. An entity will need to further analyze the transactions or quoted prices, and an adjustment to the transactions or quoted prices may be necessary to estimate fair value. Additional disclosures related to the inputs and valuation techniques used in the fair value measurements are also required. The FSP is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FES and the Utilities will adopt the FSP for their interim period ending June 30, 2009. While the FSP will expand disclosure requirements, FES and the Utilities do not expect the FSP to have a material effect upon their financial statements.

FSP FAS 115-2 and FAS 124-2 - ~~“Disclosures about Derivative Instruments~~“Recognition and ~~Hedging Activities – an Amendment~~Presentation of ~~FASB Statement No. 133”~~Other-Than-Temporary Impairments”

In April 2009, the FASB issued Staff Position FAS 115-2 and FAS 124-2, which changes the method to determine whether an other-than-temporary impairment exists for debt securities and the amount of impairment to be recorded in earnings. Under the FSP, management will be required to assert it does not have the intent to sell the debt security, and it is more likely than not it will not have to sell the debt security before recovery of its cost basis. If management is unable to make these assertions, the debt security will be deemed other-than-temporarily impaired and the security will be written down to fair value with the full charge recorded through earnings. If management is able to make the assertions, but there are credit losses associated with the debt security, the portion of impairment related to credit losses will be recognized in earnings while the remaining impairment will be recognized through other comprehensive income. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FES and the Utilities will adopt the FSP for their interim period ending June 30, 2009 and do not expect the FSP to have a material effect upon their financial statements.

FSP FAS 107-1 and APB 28-1 - “Interim Disclosures about Fair Value of Financial Instruments”

In April 2009, the FASB issued Staff Position FAS 107-1 and APB 28-1, which requires disclosures of the fair value of financial instruments in interim financial statements, as well as in annual financial statements. The FSP also requires entities to disclose the methods and significant assumptions used to estimate the fair value of financial instruments in both interim and annual financial statements. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FES and the Utilities will adopt the FSP for their interim period ending June 30, 2009, and expect to expand their disclosures regarding the fair value of financial instruments.

FSP FAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”

In December 2008, the FASB issued SFAS 161 that enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. The FASB believes that additional required disclosure of the fair values of derivative instruments and their gains and losses in a tabular format will provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effectStaff Position FAS 132(R)-1, which provides guidance on an ~~entity’s liquidity from using derivatives.~~employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This ~~Statement also requires cross-referencing within the footnotes to help users of financial statements locate important information about derivative instruments. The Statement~~FSP is effective for fiscal years ~~beginning on or~~ending after December 15, ~~2008.~~ 2009. FES and the Utilities will expand their disclosures related to postretirement benefit plan assets as a result of this FSP.

Recent Developments (Applicable to FES and each of the Utilities to the extent indicated)

On April 6, 2009, Richard H. Marsh, Senior Vice President and Chief Financial Officer (CFO) of FirstEnergy indicated his intention to step down as CFO on May 1, 2009, and retire from FirstEnergy effective July 1, 2009. Mr. Marsh was also Senior Vice President and CFO of FES and each of the Utilities except JCP&L and a Director of FES, OE, CEI and TE. On April 8, 2009, FirstEnergy’s Board of Directors elected Mark T. Clark, Executive Vice President and CFO to succeed Mr. Marsh as CFO of FirstEnergy, effective May 1, 2009. Mr. Clark also became Executive Vice President and CFO of FES and each of the Utilities except JCP&L and a Director of FES, OE, CEI and TE, effective May 1, 2009.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

FirstEnergy is ~~currently evaluating~~a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and its subsidiaries FGCO and NGC, and FESC.

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

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2008 for FirstEnergy, FES and the Utilities. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utilities reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 6) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.

The consolidated financial statements as of March 31, 2009, and for the three-month periods ended March 31, 2009 and 2008, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated May 7, 2009) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.

2. EARNINGS PER SHARE

Reconciliation of Basic and Diluted		Three Months Ended March 31
Earnings per Share of Common Stock		2009		2008
	(In millions, except per share amounts)
Earnings available to parent		$	119	$	276

Average shares of common stock outstanding – Basic			304		304
Assumed exercise of dilutive stock options and awards			2		3
Average shares of common stock outstanding – Diluted			306		307

Basic earnings per share of common stock		$	0.39	$	0.91
Diluted earnings per share of common stock		$	0.39	$	0.90

3. FAIR VALUE MEASURES

FirstEnergy’s valuation techniques, including the three levels of the fair value hierarchy as defined by SFAS 157, are disclosed in Note 5 of the Notes to Consolidated Financial Statements in FirstEnergy’s Annual Report.

The following table sets forth FirstEnergy’s financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of March 31, 2009 and December 31, 2008. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair valuation of assets and liabilities and their placement within the fair value hierarchy levels.

Recurring Fair Value Measures
as of March 31, 2009	Level 1		Level 2		Level 3		Total
	(In millions)
Assets:
Derivatives	$	-	$	43	$	-	$	43
Available-for-sale securities(1)		427		1,533		-		1,960
NUG contracts(2)		-		-		340		340
Other investments		-		80		-		80
Total	$	427	$	1,656	$	340	$	2,423

Liabilities:
Derivatives	$	30	$	27	$	-	$	57
NUG contracts(2)		-		-		816		816
Total	$	30	$	27	$	816	$	873

(1)	Primarily consists of investments in nuclear decommissioning trusts, the spent nuclear fuel trusts and the NUG trusts. Balance excludes $3 million of receivables, payables and accrued income.

(2)	NUG contracts are completely offset by regulatory assets.

Recurring Fair Value Measures
as of December 31, 2008	Level 1		Level 2		Level 3		Total
	(In millions)
Assets:
Derivatives	$	-	$	40	$	-	$	40
Available-for-sale securities(1)		537		1,464		-		2,001
NUG contracts(2)		-		-		434		434
Other investments		-		83		-		83
Total	$	537	$	1,587	$	434	$	2,558

Liabilities:
Derivatives	$	25	$	31	$	-	$	56
NUG contracts(2)		-		-		766		766
Total	$	25	$	31	$	766	$	822

(1)

Primarily consists of investments in nuclear decommissioning trusts, the spent nuclear fuel trusts and the NUG trusts.

Balance excludes $5 million of receivables, payables and accrued income.

(2) 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 nonperformance risk, including counterparty credit risk and the impact of ~~adopting~~credit enhancements (such as cash deposits, LOCs and priority interests). The impact of nonperformance risk was immaterial in the fair value measurements.

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, 2009 and 2008 (in millions):

	Three Months Ended March 31
	2009			2008
Balance as of January 1	$	(332	)	$	(803	)
Settlements(1)		83			64
Unrealized gains (losses)(1)		(227	)		320
Net transfers to (from) Level 3		-			-
Balance as of March 31, 2009	$	(476	)	$	(419	)

Change in unrealized gains (losses) relating to
instruments held as of March 31	$	(227	)	$	320

(1) Changes in the fair value of NUG contracts are completely offset by regulatory assets and do not impact earnings.

On January 1, 2009, FirstEnergy adopted FSP FAS 157-2, for financial assets and financial liabilities measured at fair value on a non-recurring basis. The impact of SFAS 157 on those financial assets and financial liabilities is immaterial.

4. DERIVATIVE INSTRUMENTS

FirstEnergy is exposed to financial risks resulting from fluctuating 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 for risk management purposes. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight for risk management activities throughout FirstEnergy. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet those criteria are accounted for at cost. The changes in the fair value of derivative instruments that do not meet the normal purchase and normal sales criteria are recorded as other expense, as AOCL, or as part of the value of the hedged item as described below.

Interest Rate Derivatives

Under the revolving credit facility, FirstEnergy incurs variable interest charges based on LIBOR. In 2008, FirstEnergy entered into swaps with a notional value of $200 million to hedge against changes in associated interest rates. Hedges with a notional value of $100 million expire in November 2009 and the remainder expire in November 2010. The swaps are accounted for as cash flow hedges under SFAS 133. As of March 31, 2009, the fair value of outstanding swaps was $(4) million.

FirstEnergy uses forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first quarter of 2009, FirstEnergy terminated forward swaps with a notional value of $100 million when a subsidiary issued long term debt. The gain associated with the termination was $1.3 million, of which $0.3 million was ineffective and recognized as an adjustment to interest expense. The remaining effective portion will be amortized to interest expense over the life of the hedged debt. FirstEnergy currently has no outstanding forward swaps.

As of March 31, 2009 and 2008, the total fair value of outstanding interest rate derivatives was $(4) million and $(3) million, respectively. Interest rate derivatives are located in “Other Noncurrent Liabilities” in FirstEnergy’s consolidated balance sheets. The effect of interest rate derivatives on the statements of income and comprehensive income during the periods ended March 31, 2009 and 2008 were:

100

		Three Months Ended
			March 31
			2009			2008
Effective Portion			(in millions)
	Loss Recognized in AOCL	$	(2	)	$	-
	Loss Reclassified from AOCL into Interest Expense		(5	)		(4	)
Ineffective Portion
	Loss Recognized in Interest Expense		-			(1	)

Total unamortized losses included in AOCL associated with prior interest rate hedges totaled $119 million ($70 million net of tax) as of March 31, 2009. Based on current estimates, approximately $11 million will be amortized to interest expense during the next twelve months. FirstEnergy’s interest rate swaps do not include any contingent credit risk related features.

Commodity Derivatives

FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances in which the hedging relationship does not qualify for hedge accounting. Derivatives that do not qualify under the normal purchase or sales criteria or for hedge accounting as cash flow hedges are marked to market through earnings. FirstEnergy’s risk policy does not allow derivatives to be used for speculative or trading purposes. FirstEnergy hedges forecasted electric sales and purchases and anticipated natural gas purchases using forwards and options. Heating oil futures are used to hedge both oil purchases and fuel surcharges associated with rail transportation contracts. FirstEnergy’s maximum hedge term is typically two years. The effective portions of all cash flow hedges are initially recorded in AOCL and are subsequently included in net income as the underlying hedged commodities are delivered.

The following tables summarize the location and fair value of commodity derivatives in FirstEnergy’s consolidated balance sheets:

Derivative Assets						Derivative Liabilities
			Fair Value						Fair Value
			March 31,		December 31,				March 31,		December 31,
			2009		2008				2009		2008
Cash Flow Hedges			(in millions)			Cash Flow Hedges			(in millions)
Electricity Forwards						Electricity Forwards
	Current Assets	$	23	$	11		Current Liabilities	$	23	$	27
Natural Gas Futures						Natural Gas Futures
	Current Assets		-		-		Current Liabilities		11		4
	Long-Term Deferred Charges		-		-		Noncurrent Liabilities		5		5
Other						Other
	Current Assets		-		-		Current Liabilities		10		12
	Long-Term Deferred Charges		-		-		Noncurrent Liabilities		3		4
		$	23	$	11			$	52	$	52


Derivative Assets						Derivative Liabilities
			Fair Value						Fair Value
			March 31, 2009		December 31, 2008				March 31, 2009		December 31, 2008
Economic Hedges			(in millions)			Economic Hedges			(in millions)
NUG Contracts						NUG Contracts
	Power Purchase	$	340	$	434		Power Purchase	$	816	$	766
	Contract Asset						Contract Liability
Other						Other
	Current Assets		1		1		Current Liabilities		1		1
	Long-Term Deferred Charges		19		28		Noncurrent Liabilities		-		-
		$	360	$	463			$	817	$	767
Total Commodity Derivatives		$	383	$	474	Total Commodity Derivatives		$	869	$	819

Electricity forwards are used to balance expected retail and wholesale sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas, primarily used in FirstEnergy’s peaking units. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s transportation contracts. Derivative instruments are not used in quantities greater than forecasted needs. The following table summarizes the volume of FirstEnergy’s outstanding derivative transactions as of March 31, 2009.

101

	Purchases		Sales			Net			Units
		(in thousands)
Electricity Forwards		772		(1,735	)		(963	)		MWh
Heating Oil Futures		20,496		(2,520	)		17,976			Gallons
Natural Gas Futures		4,850		-			4,850			mmBtu

The effect of derivative instruments on the consolidated statements of income and comprehensive income for the three months ended March 31, 2009 and 2008, for instruments designated in cash flow hedging relationships and not in hedging relationships, respectively, are summarized in the following tables:

Derivatives in Cash Flow Hedging Relationships			Electricity			Natural Gas			Heating Oil
			Forwards			Futures			Futures			Total
2009			(in millions)
Gain (Loss) Recognized in AOCL (Effective Portion)		$	(2	)	$	(7	)	$	(1	)	$	(10	)
Effective Gain (Loss) Reclassified to:(1)
	Purchased Power Expense		(18	)		-			-			(18	)
	Fuel Expense		-			-			(4	)		(4	)


2008
Gain (Loss) Recognized in AOCL (Effective Portion)		$	(14	)	$	3		$	-		$	(11	)
Effective Gain (Loss) Reclassified to:(1)
	Purchased Power Expense		(17	)		-			-			(17	)
	Fuel Expense		-			-			-

(1) The ineffective portion was immaterial.

Derivatives Not in Hedging Relationships			NUG
			Contracts			Other			Total
2009			(in millions)
Unrealized Gain (Loss) Recognized in:
Regulatory Assets(1)		$	(227	)	$	-		$	(227	)
Realized Gain (Loss) Reclassified to:
Fuel Expense(2)		$	-		$	(1	)	$	(1	)
Regulatory Assets(3)			(83	)		10			(73	)
		$	(83	)	$	9		$	(74	)
2008
Unrealized Gain (Loss) Recognized in:
Regulatory Assets(1)		$	320		$	-		$	320

Realized Gain (Loss) Reclassified to:
	Regulatory Assets(3)	$	(64	)	$	11		$	(53	)

(1)	Changes in the fair value of NUG Contracts are deferred for future recovery from (or refund to) customers.
(2)	The realized gain (loss) is reclassified upon termination of the derivative instrument
(3)	The above market cost of NUG power is deferred for future recovery from (or refund to) customers.

Total unamortized losses included in AOCL associated with commodity derivatives were $32 million ($19 million net of tax) as of March 31, 2009, as compared to $44 million ($27 million net of tax) as of December 31, 2008. The change (net of tax) resulted from a net $5 million increase related to current hedging activity and a $13 million decrease due to net hedge losses reclassified to earnings during the first quarter of 2009. Based on current estimates, approximately $15 million (after tax) of the net deferred losses on derivative instruments in AOCL as of March 31, 2009 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.

Many of FirstEnergy’s commodity derivatives contain credit risk features. As of March 31, 2009, FirstEnergy posted $141 million of collateral related to net liability positions and held no counterparties’ funds related to asset positions. The collateral FirstEnergy has posted relates to both derivative and non-derivative contracts. FirstEnergy’s largest derivative counterparties fully collateralize all derivative transactions. Certain commodity derivative contracts include credit-risk-related contingent features that would require FirstEnergy to post additional collateral if the credit rating for its debt were to fall below investment grade. The aggregate fair value of derivative instruments with credit-risk related contingent features that are in a liability position on March 31, 2009 was $4 million, for which no collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post $4 million of additional collateral related to commodity derivatives.

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5. PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December 31. FirstEnergy also provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

For the three months ended March 31, 2009 and 2008, FirstEnergy’s net pension and OPEB expense (benefit) was $43 million and $(15) million, respectively. The components of FirstEnergy's net pension and other postretirement benefit cost (including amounts capitalized) for the three months ended March 31, 2009 and 2008, consisted of the following:

	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008
	(In millions)
Service cost	$	22		$	22		$	5		$	5
Interest cost		80			75			20			18
Expected return on plan assets		(81	)		(116	)		(9	)		(13	)
Amortization of prior service cost		3			3			(38	)		(37	)
Recognized net actuarial loss		42			2			16			12
Net periodic cost (credit)	$	66		$	(14	)	$	(6	)	$	(15	)

Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net pension and other postretirement benefit costs (including amounts capitalized) recognized by each of the Companies for the three months ended March 31, 2009 and 2008 were as follows:

	Pension Benefit Cost (Credit)					Other Postretirement Benefit Cost (Credit)
	2009		2008			2009			2008
	(In millions)
FES	$	18	$	5		$	(1	)	$	(2	)
OE		7		(6	)		(2	)		(2	)
CEI		5		(1	)		1			1
TE		2		(1	)		1			1
JCP&L		9		(3	)		(1	)		(4	)
Met-Ed		6		(2	)		(1	)		(3	)
Penelec		4		(3	)		-			(3	)
Other FirstEnergy subsidiaries		15		(3	)		(3	)		(3	)
	$	66	$	(14	)	$	(6	)	$	(15	)

6. VARIABLE INTEREST ENTITIES

FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary as defined by FIN 46R. Effective January 1, 2009, FirstEnergy adopted SFAS 160. As a result, FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest within the Consolidated Balance Sheets is the result of earnings and losses of the noncontrolling interests and distributions to owners.

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Mining Operations

On July 16, 2008, FEV entered into a joint venture with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake in the Signal Peak mining and coal transportation operations near Roundup, Montana. FEV made a $125 million equity investment in the joint venture, which acquired 80% of the mining operations (Signal Peak Energy, LLC) and 100% of the transportation operations, with FEV owning a 45% economic interest and an affiliate of the Boich Companies owning a 55% economic interest in the joint venture. Both parties have a 50% voting interest in the joint venture. In March 2009, FEV agreed to pay a total of $8.5 million (of which $1.7 million was paid in March 2009) to affiliates of the Boich Companies to purchase an additional 5% economic interest in the Signal Peak mining and coal transportation operations. Voting interests will remain unchanged after the sale is completed in July 2009. Effective January 16, 2010, the joint venture will have 18 months to exercise an option to acquire the remaining 20% stake in the mining operations. In accordance with FIN 46R, FEV consolidates the mining and transportation operations of this ~~Standard~~joint venture in its financial statements.

Trusts

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

Loss Contingencies

FES and the Ohio Companies are exposed to losses under their applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions mentioned above:

	Maximum Exposure		Discounted Lease Payments, net(1)		Net Exposure
	(In millions)
FES	$	1,373	$	1,202	$	171
OE	759		587		172
CEI	740		73		667
TE	740		419		321

(1) The net present value of FirstEnergy’s consolidated sale and leaseback operating

lease commitments is $1.7 billion

In October 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. FGCO assumed all of CEI’s and TE’s obligations arising under those leases. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCO’s leasehold interests under its July 2007 Bruce Mansfield Unit 1 sale and leaseback transaction to a newly formed wholly-owned subsidiary in December 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE remain primarily liable on the 1987 leases and related agreements as to the lessors and other parties to the agreements. FGCO remains primarily liable on the 2007 leases and related agreements, and FES remains primarily liable as a guarantor under the related 2007 guarantees, as to the lessors and other parties to the respective agreements. These assignments terminate automatically upon the termination of the underlying leases.

During the second quarter of 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant and approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. In addition, NGC purchased 158.5 MW of lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2. The Ohio Companies continue to lease these MW under their respective sale and leaseback arrangements and the related lease debt remains outstanding.

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Power Purchase Agreements

In accordance with FIN 46R, FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Companies and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains 24 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it may incur for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs from these entities during the three months ended March 31, 2009 and 2008 are shown in the following table:

	Three Months Ended
	March 31,
	2009		2008
	(In millions)
JCP&L	$	19	$	19
Met-Ed		15		16
Penelec		9		8
	$	43	$	43

Transition Bonds

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of March 31, 2009, $363 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.

7. INCOME TAXES

FirstEnergy accounts for uncertainty in income taxes recognized in a company’s financial statements in accordance with FIN 48. This interpretation prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. Upon completion of the federal tax examination for the 2007 tax year in the first quarter of 2009, FirstEnergy recognized $13 million in tax benefits, which favorably affected FirstEnergy’s effective tax rate. During the first three months of 2008, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of March 31, 2009, FirstEnergy expects that it is reasonably possible that $193 million of the unrecognized benefits may be resolved within the next twelve months, of which approximately $148 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs, gains and losses recognized on the disposition of assets and various other tax items.

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FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. The net amount of accumulated interest accrued as of March 31, 2009 was $61 million, as compared to $59 million as of December 31, 2008. During the first three months of 2009 and 2008, there were no material changes to the amount of interest accrued.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2008. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audits for the years 2004-2006 were completed in 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 under its Compliance Assurance Process program and was completed in the first quarter of 2009 with two items under appeal. The IRS began auditing the year 2008 in February 2008 and the year 2009 in February 2009 under its Compliance Assurance Process program. Neither audit is expected to close before December 2009. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

8. COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A) GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of March 31, 2009, outstanding guarantees and other assurances aggregated approximately $4.5 billion, consisting of parental guarantees - $1.2 billion, subsidiaries’ guarantees - $2.6 billion, surety bonds - $0.1 billion and LOCs - $0.6 billion.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge 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 obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4 billion (included in the $1.2 billion discussed above) as of March 31, 2009 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of March 31, 2009, FirstEnergy's maximum exposure under these collateral provisions was $761 million, consisting of $55 million due to “material adverse event” contractual clauses and $706 million due to a below investment grade credit rating. Additionally, stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase this amount to $830 million, consisting of $54 million due to “material adverse event” contractual clauses and $776 million due to a below investment grade credit rating.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $111 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ contracts as of March 31, 2009, and forward prices as of that date, FES had $205 million of outstanding collateral payments. Under a hypothetical adverse change in forward prices (15% decrease in the first 12 months and 20% decrease in prices thereafter), FES would be required to post an additional $77 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post significantly higher amounts for margining.

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In July 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully and unconditionally guaranteed all of FGCO’s obligations under each of the leases (see Note 12). 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.

On October 8, 2008, to enhance their liquidity position in the face of the turbulent credit and bond markets, FirstEnergy, FES and FGCO entered into a $300 million secured term loan facility with Credit Suisse. Under the facility, FGCO is the borrower and FES and FirstEnergy are guarantors. Generally, the facility is available to FGCO until October 7, 2009, with a minimum borrowing amount of $100 million and maturity 30 days from the date of the borrowing. Once repaid, borrowings may not be re-borrowed.

(B)	ENVIRONMENTAL MATTERS

Clean Air Act Compliance

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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. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints. The Pennsylvania Department of Health and the U.S. Agency for Toxic Substance and Disease Registry recently disclosed their intention to conduct additional air monitoring in the vicinity of the Mansfield plant.

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National Ambient Air Quality Standards

In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR 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), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. The future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. The EPA is developing new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

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

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration had committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, former President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity in the United States comes from renewable sources by 2012, and increasing to 25% by 2025; and implementing an economy-wide cap-and-trade program to reduce GHG emissions 80% by 2050.

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

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Clean Water Act

Regulation of Waste Disposal

110

The Utilities have been named as potentially responsible parties 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 potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $91 million (JCP&L - - $64 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through March 31, 2009. Included in the total are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

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, the Muise class action) 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.

Nuclear Plant Matters

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In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.

Other Legal Matters

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. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009; the appeal process could take as long as 24 months. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.

9. REGULATORY MATTERS

(A) RELIABILITY INITIATIVES

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 Utilities and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including 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.

In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the MISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards.

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(B) OHIO

113

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

On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded and the companies are awaiting a Recommended Decision from the ALJ. The TSCs include a component from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.

On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. The bill addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters and alternative energy. Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. Similar guidelines related to Smart Meter deployment were issued for comment on March 30, 2009.

Major provisions of the legislation include:

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

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

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

114

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

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

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

(D) NEW JERSEY

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 DPA 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 March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.

115

The EMP was issued on October 22, 2008, establishing five major goals:

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

·	reduce peak demand for electricity by 5,700 MW by 2020;

·	meet 30% of the state’s electricity needs with renewable energy by 2020;

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

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

On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by December 31, 2009 by New Jersey electric and gas utilities in order to achieve the goals of the EMP. At this time, FirstEnergy cannot determine the impact, if any, the EMP may have on its operations or those of JCP&L.

(E) FERC MATTERS

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.

PJM Transmission Rate

116

The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce the costs of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.

Post Transition Period Rate Design

Duquesne’s Request to Withdraw from PJM

117

Changes ordered for PJM Reliability Pricing Model (RPM) Auction

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’ request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement talks. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.

MISO Resource Adequacy Proposal

FES Sales to Affiliates

118

FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of the December 23, 2008 waiver.

10. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

FSP FAS 157-4 – “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”

In April 2009, the FASB issued Staff Position FAS 157-4, which provides additional guidance to consider in estimating fair value when there has been a significant decrease in market activity for a financial asset. The FSP establishes a two-step process requiring a reporting entity to first determine if a market is not active in relation to normal market activity for the asset. If evidence indicates the market is not active, an entity would then need to determine whether a quoted price in the market is associated with a distressed transaction. An entity will need to further analyze the transactions or quoted prices, and an adjustment to the transactions or quoted prices may be necessary to estimate fair value. Additional disclosures related to the inputs and valuation techniques used in the fair value measurements are also required. The FSP is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009. While the FSP will expand disclosure requirements, FirstEnergy does not expect the FSP to have a material effect upon its financial statements.

~~SFAS 162~~FSP FAS 115-2 and FAS 124-2 - ~~“The Hierarchy~~“Recognition and Presentation of ~~Generally Accepted Accounting Principles”~~Other-Than-Temporary Impairments”

In ~~May~~April 2009, the FASB issued Staff Position FAS 115-2 and FAS 124-2, which changes the method to determine whether an other-than-temporary impairment exists for debt securities and the amount of impairment to be recorded in earnings. Under the FSP, management will be required to assert it does not have the intent to sell the debt security, and it is more likely than not it will not have to sell the debt security before recovery of its cost basis. If management is unable to make these assertions, the debt security will be deemed other-than-temporarily impaired and the security will be written down to fair value with the full charge recorded through earnings. If management is able to make the assertions, but there are credit losses associated with the debt security, the portion of impairment related to credit losses will be recognized in earnings while the remaining impairment will be recognized through other comprehensive income. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009 and does not expect the FSP to have a material effect upon its financial statements.

FSP FAS 107-1 and APB 28-1 - “Interim Disclosures about Fair Value of Financial Instruments”

FSP FAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”

In December 2008, the FASB issued ~~SFAS 162,~~Staff Position FAS 132(R)-1, which ~~is intended to improve financial reporting by identifying~~provides guidance on an employer’s disclosures about plan assets of a ~~consistent framework,~~defined benefit pension or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP. The FASB believes that the GAAP hierarchy should be directed to reporting entities, not the independent auditors, because reporting entities are responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP.other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This ~~Statement~~FSP is effective ~~60 days following the SEC’s approval~~for fiscal years ending after December 15, 2009. FirstEnergy will expand its disclosures related to postretirement benefit plan assets as a result of ~~the PCAOB amendments to U.S. Auditing Standards Section 411,~~ ~~The Meaning of~~ ~~Present Fairly in Conformity With Generally Accepted Accounting Principles, which has not yet occurred. The Statement will not have an impact on FirstEnergy’s financial statements.~~this FSP.

~~13.~~

119

11. 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~~all other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”

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

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

The Ohio transitional generation services segment represents the regulated generation commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect the purchase of electricity from third parties and the competitive energy services segment through ~~full-requirements PSA arrangements,~~a CBP, 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)
June 30, 2008
External revenues $ 2,182 $ 375 $ 683 $ 20 $ (15 ) $ 3,245
Internal revenues - 704 - - (704 ) -
Total revenues 2,182 1,079 683 20 (719 ) 3,245
Depreciation and amortization 241 59 11 1 4 316
Investment income 40 (8 ) (1 ) 6 (21 ) 16
Net interest charges 99 28 - - 48 175
Income taxes 129 45 13 (1 ) (26 ) 160
Net income 193 66 19 26 (41 ) 263
Total assets 23,423 9,240 266 281 335 33,545
Total goodwill 5,582 24 - - - 5,606
Property additions 196 683 - 9 18 906

June 30, 2007
External revenues $ 2,095 $ 398 $ 625 $ 9 $ (18 ) $ 3,109
Internal revenues - 691 - - (691 ) -
Total revenues 2,095 1,089 625 9 (709 ) 3,109
Depreciation and amortization 249 51 (49 ) 1 5 257
Investment income 62 5 - - (37 ) 30
Net interest charges 116 42 - 1 39 198
Income taxes 141 96 19 (3 ) (31 ) 222
Net income 207 142 30 6 (47 ) 338
Total assets 23,602 7,284 260 236 651 32,033
Total goodwill 5,874 24 - - - 5,898
Property additions 245 139 - 2 15 401

Six Months Ended

June 30, 2008

External revenues $ 4,394 $ 704 $ 1,390 $ 60 $ (26 ) $ 6,522
Internal revenues - 1,480 - - (1,480 ) -
Total revenues 4,394 2,184 1,390 60 (1,506 ) 6,522
Depreciation and amortization 496 112 15 1 9 633
Investment income 85 (14 ) - 6 (44 ) 33
Net interest charges 202 55 - - 89 346
Income taxes 248 103 28 13 (45 ) 347
Net income 372 153 42 48 (76 ) 539
Total assets 23,423 9,240 266 281 335 33,545
Total goodwill 5,582 24 - - - 5,606
Property additions 451 1,145 - 21 - 1,617

June 30, 2007

External revenues $ 4,135 $ 719 $ 1,245 $ 20 $ (37 ) $ 6,082
Internal revenues - 1,404 - - (1,404 ) -
Total revenues 4,135 2,123 1,245 20 (1,441 ) 6,082
Depreciation and amortization 469 102 (64 ) 2 11 520
Investment income 132 8 1 - (78 ) 63
Net interest charges 223 92 1 2 60 378
Income taxes 289 160 35 2 (64 ) 422
Net income 425 240 53 7 (97 ) 628
Total assets 23,602 7,284 260 236 651 32,033
Total goodwill 5,874 24 - - - 5,898
Property additions 400 263 - 3 31 697

Segment Financial Information
							Ohio
	Energy			Competitive			Transitional
	Delivery			Energy			Generation						Reconciling
Three Months Ended	Services			Services			Services			Other			Adjustments			Consolidated
	(In millions)
March 31, 2009
External revenues	$	2,109		$	335		$	912		$	7		$	(29	)	$	3,334
Internal revenues		-			893			-			-			(893	)		-
Total revenues		2,109			1,228			912			7			(922	)		3,334
Depreciation and amortization		472			64			(45	)		1			3			495
Investment income (loss), net		29			(29	)		1			-			(12	)		(11	)
Net interest charges		110			18			-			1			37			166
Income taxes		(28	)		103			16			(17	)		(20	)		54
Net income (loss)		(42	)		155			24			17			(39	)		115
Total assets		22,669			9,925			336			632			(5	)		33,557
Total goodwill		5,550			24			-			-			-			5,574
Property additions		165			421			-			49			19			654

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 (loss), net		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			(34	)		277
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

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.

47120

~~14.~~12. 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 fully and unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty. This transaction is classified as an operating lease under GAAP for FES and ~~FirstEnergy and~~ a financing for FGCO.

The condensed consolidating statements of income for the ~~three-month~~three months ended March 31, 2009, and ~~six-month periods ended June 30,~~ 2008, ~~and 2007,~~ consolidating balance sheets as of ~~June 30, 2008~~March 31, 2009, and December 31, ~~2007~~2008, and ~~condensed~~ consolidating statements of cash flows for the ~~six-months~~three months ended ~~June 30,~~March 31, 2009, and 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 the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

48121

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended June 30, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 1,064,627 $ 565,225 $ 287,028 $ (845,602 ) $ 1,071,278

EXPENSES:
Fuel 3,605 277,192 29,753 - 310,550
Purchased power from non-affiliates 220,339 - - - 220,339
Purchased power from affiliates 842,670 2,932 34,528 (845,602 ) 34,528
Other operating expenses 29,842 124,173 121,534 12,189 287,738
Provision for depreciation 1,600 30,027 25,893 (1,360 ) 56,160
General taxes 4,727 11,504 3,564 - 19,795
Total expenses 1,102,783 445,828 215,272 (834,773 ) 929,110

OPERATING INCOME (LOSS) (38,156 ) 119,397 71,756 (10,829 ) 142,168

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees 98,590 489 (9,449 ) (91,704 ) (2,074 )
Interest expense - affiliates (50 ) (7,920 ) (2,758 ) - (10,728 )
Interest expense - other (6,663 ) (23,697 ) (10,632 ) 16,487 (24,505 )
Capitalized interest 28 9,856 657 - 10,541
Total other income (expense) 91,905 (21,272 ) (22,182 ) (75,217 ) (26,766 )

INCOME BEFORE INCOME TAXES 53,749 98,125 49,574 (86,046 ) 115,402

INCOME TAXES (BENEFIT) (14,345 ) 38,467 20,838 2,348 47,308

NET INCOME $ 68,094 $ 59,658 $ 28,736 $ (88,394 ) $ 68,094

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended March 31, 2009	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)

REVENUES	$	1,201,895		$	545,926		$	395,628		$	(917,343	)	$	1,226,106

EXPENSES:
Fuel		2,095			274,847			29,216			-			306,158
Purchased power from non-affiliates		160,342			-			-			-			160,342
Purchased power from affiliates		915,261			2,082			63,207			(917,343	)		63,207
Other operating expenses		38,267			104,443			152,456			12,190			307,356
Provision for depreciation		1,019			30,020			31,649			(1,315	)		61,373
General taxes		4,706			12,626			6,044			-			23,376
Total expenses		1,121,690			424,018			282,572			(906,468	)		921,812

OPERATING INCOME		80,205			121,908			113,056			(10,875	)		304,294

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		120,513			(47	)		(29,637	)		(117,192	)		(26,363	)
Interest expense to affiliates		(34	)		(1,758	)		(1,187	)		-			(2,979	)
Interest expense - other		(2,520	)		(21,058	)		(15,168	)		16,219			(22,527	)
Capitalized interest		51			7,750			2,277			-			10,078
Total other income (expense)		118,010			(15,113	)		(43,715	)		(100,973	)		(41,791	)

INCOME BEFORE INCOME TAXES		198,215			106,795			69,341			(111,848	)		262,503

INCOME TAXES		27,534			39,142			22,929			2,217			91,822

NET INCOME	$	170,681		$	67,653		$	46,412		$	(114,065	)	$	170,681

122

FIRSTENERGY SOLUTIONS CORP.

CONDENSED 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

123

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

As of March 31, 2009	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	-	$	34	$	-	$	-		$	34
Receivables-
Customers		54,554		-		-		-			54,554
Associated companies		295,513		192,816		125,514		(325,908	)		287,935
Other		2,562		14,705		49,026		-			66,293
Notes receivable from associated companies		404,869		28,268		-		-			433,137
Materials and supplies, at average cost		8,610		349,038		210,039		-			567,687
Prepayments and other		84,466		26,589		1,107		-			112,162
		850,574		611,450		385,686		(325,908	)		1,521,802

PROPERTY, PLANT AND EQUIPMENT:
In service		88,064		5,477,939		4,736,544		(389,944	)		9,912,603
Less - Accumulated provision for depreciation		10,821		2,732,040		1,755,879		(171,499	)		4,327,241
		77,243		2,745,899		2,980,665		(218,445	)		5,585,362
Construction work in progress		4,728		1,626,685		483,418		-			2,114,831
		81,971		4,372,584		3,464,083		(218,445	)		7,700,193

INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		995,476		-			995,476
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		3,712,870		-		-		(3,712,870	)		-
Other		1,714		29,982		202		-			31,898
		3,714,584		29,982		1,058,578		(3,712,870	)		1,090,274

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		18,209		458,730		-		(235,332	)		241,607
Lease assignment receivable from associated companies		-		71,356		-		-			71,356
Goodwill		24,248		-		-		-			24,248
Property taxes		-		27,494		22,610		-			50,104
Unamortized sale and leaseback costs		-		32,128		-		54,174			86,302
Other		65,233		58,004		8,332		(44,428	)		87,141
		107,690		647,712		30,942		(225,586	)		560,758
	$	4,754,819	$	5,661,728	$	4,939,289	$	(4,482,809	)	$	10,873,027

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	708	$	930,763	$	777,218	$	(17,747	)	$	1,690,942
Short-term borrowings-
Associated companies		-		345,664		440,452		-			786,116
Other		1,100,000		-		-		-			1,100,000
Accounts payable-
Associated companies		361,848		132,694		232,204		(317,586	)		409,160
Other		27,081		117,756		-		-			144,837
Accrued taxes		22,861		75,462		45,300		(20,889	)		122,734
Other		58,938		112,048		23,023		45,975			239,984
		1,571,436		1,714,387		1,518,197		(310,247	)		4,493,773

CAPITALIZATION:
Common stockholder's equity		3,120,406		1,901,085		1,797,764		(3,698,849	)		3,120,406
Long-term debt and other long-term obligations		21,819		1,466,373		469,839		(1,287,970	)		670,061
		3,142,225		3,367,458		2,267,603		(4,986,819	)		3,790,467

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,018,156			1,018,156
Accumulated deferred income taxes		-		-		203,899		(203,899	)		-
Accumulated deferred investment tax credits		-		38,669		22,976		-			61,645
Asset retirement obligations		-		24,274		852,799		-			877,073
Retirement benefits		23,242		175,561		-		-			198,803
Property taxes		-		27,494		22,610		-			50,104
Lease market valuation liability		-		296,376		-		-			296,376
Other		17,916		17,509		51,205		-			86,630
		41,158		579,883		1,153,489		814,257			2,588,787
	$	4,754,819	$	5,661,728	$	4,939,289	$	(4,482,809	)	$	10,873,027

124

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2008	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	-	$	39	$	-	$	-		$	39
Receivables-
Customers		86,123		-		-		-			86,123
Associated companies		363,226		225,622		113,067		(323,815	)		378,100
Other		991		11,379		12,256		-			24,626
Notes receivable from associated companies		107,229		21,946		-		-			129,175
Materials and supplies, at average cost		5,750		303,474		212,537		-			521,761
Prepayments and other		76,773		35,102		660		-			112,535
		640,092		597,562		338,520		(323,815	)		1,252,359

PROPERTY, PLANT AND EQUIPMENT:
In service		134,905		5,420,789		4,705,735		(389,525	)		9,871,904
Less - Accumulated provision for depreciation		13,090		2,702,110		1,709,286		(169,765	)		4,254,721
		121,815		2,718,679		2,996,449		(219,760	)		5,617,183
Construction work in progress		4,470		1,441,403		301,562		-			1,747,435
		126,285		4,160,082		3,298,011		(219,760	)		7,364,618

INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,033,717		-			1,033,717
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		3,596,152		-		-		(3,596,152	)		-
Other		1,913		59,476		202		-			61,591
		3,598,065		59,476		1,096,819		(3,596,152	)		1,158,208

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		24,703		476,611		-		(233,552	)		267,762
Lease assignment receivable from associated companies		-		71,356		-		-			71,356
Goodwill		24,248		-		-		-			24,248
Property taxes		-		27,494		22,610		-			50,104
Unamortized sale and leaseback costs		-		20,286		-		49,646			69,932
Other		59,642		59,674		21,743		(44,625	)		96,434
		108,593		655,421		44,353		(228,531	)		579,836
	$	4,473,035	$	5,472,541	$	4,777,703	$	(4,368,258	)	$	10,355,021

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	5,377	$	925,234	$	1,111,183	$	(16,896	)	$	2,024,898
Short-term borrowings-
Associated companies		1,119		257,357		6,347		-			264,823
Other		1,000,000		-		-		-			1,000,000
Accounts payable-
Associated companies		314,887		221,266		250,318		(314,133	)		472,338
Other		35,367		119,226		-		-			154,593
Accrued taxes		8,272		60,385		30,790		(19,681	)		79,766
Other		61,034		136,867		13,685		36,853			248,439
		1,426,056		1,720,335		1,412,323		(313,857	)		4,244,857

CAPITALIZATION:
Common stockholder's equity		2,944,423		1,832,678		1,752,580		(3,585,258	)		2,944,423
Long-term debt and other long-term obligations		61,508		1,328,921		469,839		(1,288,820	)		571,448
		3,005,931		3,161,599		2,222,419		(4,874,078	)		3,515,871

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,026,584			1,026,584
Accumulated deferred income taxes		-		-		206,907		(206,907	)		-
Accumulated deferred investment tax credits		-		39,439		23,289		-			62,728
Asset retirement obligations		-		24,134		838,951		-			863,085
Retirement benefits		22,558		171,619		-		-			194,177
Property taxes		-		27,494		22,610		-			50,104
Lease market valuation liability		-		307,705		-		-			307,705
Other		18,490		20,216		51,204		-			89,910
		41,048		590,607		1,142,961		819,677			2,594,293
	$	4,473,035	$	5,472,541	$	4,777,703	$	(4,368,258	)	$	10,355,021

125

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Three Months Ended March 31, 2009	FES			FGCO			NGC			Eliminations		Consolidated
	(In thousands)


NET CASH PROVIDED FROM OPERATING ACTIVITIES	$	200,420		$	28,545		$	118,902		$	-	$	347,867

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			100,000			-			-		100,000
Short-term borrowings, net		98,881			88,308			434,105			-		621,294
Redemptions and Repayments-
Long-term debt		(1,189	)		(626	)		(334,101	)		-		(335,916	)
Net cash provided from financing activities		97,692			187,682			100,004			-		385,378

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(358	)		(198,631	)		(213,816	)		-		(412,805	)
Proceeds from asset sales		-			7,573			-			-		7,573
Sales of investment securities held in trusts		-			-			351,414			-		351,414
Purchases of investment securities held in trusts		-			-			(356,904	)		-		(356,904	)
Loans to associated companies, net		(297,641	)		(6,322	)		-			-		(303,963	)
Other		(113	)		(18,852	)		400			-		(18,565	)
Net cash used for investing activities		(298,112	)		(216,232	)		(218,906	)		-		(733,250	)

Net change in cash and cash equivalents		-			(5	)		-			-		(5	)
Cash and cash equivalents at beginning of period		-			39			-			-		39
Cash and cash equivalents at end of period	$	-		$	34		$	-		$	-	$	34

126

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

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended June 30, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 1,074,858 $ 453,553 $ 279,092 $ (738,772 ) $ 1,068,731

EXPENSES:
Fuel 7,513 235,653 25,714 - 268,880
Purchased power from non-affiliates 162,873 - - - 162,873
Purchased power from affiliates 731,260 57,291 20,806 (738,772 ) 70,585
Other operating expenses 30,519 65,694 136,932 - 233,145
Provision for depreciation 469 25,239 22,812 - 48,520
General taxes 5,602 9,050 6,258 - 20,910
Total expenses 938,236 392,927 212,522 (738,772 ) 804,913

OPERATING INCOME 136,622 60,626 66,570 - 263,818

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees 74,781 (622 ) 4,215 (63,005 ) 15,369
Interest expense - affiliates - (17,990 ) (4,827 ) - (22,817 )
Interest expense - other (5,773 ) (6,116 ) (9,804 ) - (21,693 )
Capitalized interest 6 3,056 1,361 - 4,423
Total other income (expense) 69,014 (21,672 ) (9,055 ) (63,005 ) (24,718 )

INCOME BEFORE INCOME TAXES 205,636 38,954 57,515 (63,005 ) 239,100

INCOME TAXES 54,220 12,892 20,572 - 87,684

NET INCOME $ 151,416 $ 26,062 $ 36,943 $ (63,005 ) $ 151,416

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Six Months Ended June 30, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 2,164,475 $ 1,132,926 $ 612,712 $ (1,739,719 ) $ 2,170,394

EXPENSES:
Fuel 5,743 568,431 58,065 - 632,239
Purchased power from non-affiliates 427,063 - - - 427,063
Purchased power from affiliates 1,734,649 5,070 60,013 (1,739,719 ) 60,013
Other operating expenses 67,438 231,340 261,129 24,377 584,284
Provision for depreciation 1,907 56,626 50,087 (2,718 ) 105,902
General taxes 10,142 23,074 9,776 - 42,992
Total expenses 2,246,942 884,541 439,070 (1,718,060 ) 1,852,493

OPERATING INCOME (LOSS) (82,467 ) 248,385 173,642 (21,659 ) 317,901

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees 220,315 (719 ) (15,986 ) (208,588 ) (4,978 )
Interest expense - affiliates (132 ) (13,209 ) (4,597 ) - (17,938 )
Interest expense - other (10,641 ) (49,665 ) (21,650 ) 32,916 (49,040 )
Capitalized interest 49 16,084 1,071 - 17,204
Total other income (expense) 209,591 (47,509 ) (41,162 ) (175,672 ) (54,752 )

INCOME BEFORE INCOME TAXES 127,124 200,876 132,480 (197,331 ) 263,149

INCOME TAXES (BENEFIT) (30,954 ) 77,752 53,602 4,671 105,071

NET INCOME $ 158,078 $ 123,124 $ 78,878 $ (202,002 ) $ 158,078

51127

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Six Months Ended June 30, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 2,094,245 $ 1,004,908 $ 513,183 $ (1,525,312 ) $ 2,087,024

EXPENSES:
Fuel 9,880 436,884 55,651 - 502,415
Purchased power from non-affiliates 349,076 - - - 349,076
Purchased power from affiliates 1,515,432 118,727 38,221 (1,525,312 ) 147,068
Other operating expenses 81,768 164,789 250,184 - 496,741
Provision for depreciation 922 50,175 45,433 - 96,530
General taxes 10,536 19,618 12,474 - 42,628
Total expenses 1,967,614 790,193 401,963 (1,525,312 ) 1,634,458

OPERATING INCOME 126,631 214,715 111,220 - 452,566

OTHER INCOME (EXPENSE):
Miscellaneous income, including
net income from equity investees 188,729 294 9,415 (163,337 ) 35,101
Interest expense - affiliates - (42,321 ) (9,942 ) - (52,263 )
Interest expense - other (7,158 ) (12,876 ) (19,017 ) - (39,051 )
Capitalized interest 11 5,155 2,466 - 7,632
Total other income (expense) 181,582 (49,748 ) (17,078 ) (163,337 ) (48,581 )

INCOME BEFORE INCOME TAXES 308,213 164,967 94,142 (163,337 ) 403,985

INCOME TAXES 54,293 62,181 33,591 - 150,065

NET INCOME $ 253,920 $ 102,786 $ 60,551 $ (163,337 ) $ 253,920

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of June 30, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2 $ - $ - $ - $ 2
Receivables-
Customers 117,858 - - - 117,858
Associated companies 419,402 259,454 80,249 (285,131 ) 473,974
Other 1,475 1,376 5,105 - 7,956
Notes receivable from associated companies 554,279 - - - 554,279
Materials and supplies, at average cost 2,942 281,275 205,327 - 489,544
Prepayments and other 141,414 30,300 695 - 172,409
1,237,372 572,405 291,376 (285,131 ) 1,816,022

PROPERTY, PLANT AND EQUIPMENT:
In service 82,280 5,385,410 4,666,202 (391,896 ) 9,741,996
Less - Accumulated provision for depreciation 9,411 2,684,494 1,609,851 (169,476 ) 4,134,280
72,869 2,700,916 3,056,351 (222,420 ) 5,607,716
Construction work in progress 11,373 1,064,083 145,833 - 1,221,289
84,242 3,764,999 3,202,184 (222,420 ) 6,829,005
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts - - 1,234,635 - 1,234,635
Long-term notes receivable from associated companies - - 62,900 - 62,900
Investment in associated companies 2,677,674 - - (2,677,674 ) -
Other 2,323 63,467 202 - 65,992
2,679,997 63,467 1,297,737 (2,677,674 ) 1,363,527
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes 16,722 480,721 - (249,475 ) 247,968
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 3,211 12,206 - - 15,417
Unamortized sale and leaseback costs - 23,282 - 50,096 73,378
Other 8,473 58,569 8,813 (47,063 ) 28,792
52,654 667,041 31,580 (246,442 ) 504,833
$ 4,054,265 $ 5,067,912 $ 4,822,877 $ (3,431,667 ) $ 10,513,387
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 4,679 $ 873,562 $ 1,077,289 $ (17,315 ) $ 1,938,215
Short-term borrowings-
Associated companies - 774,490 442,217 - 1,216,707
Other 1,000,000 - - - 1,000,000
Accounts payable-
Associated companies 275,820 253,818 93,599 (275,431 ) 347,806
Other 81,252 133,486 - - 214,738
Accrued taxes 1,162 58,976 19,393 (6,993 ) 72,538
Other 116,036 98,885 14,607 34,697 264,225
1,478,949 2,193,217 1,647,105 (265,042 ) 5,054,229
CAPITALIZATION:
Common stockholder's equity 2,505,676 1,071,297 1,596,565 (2,667,862 ) 2,505,676
Long-term debt and other long-term obligations 41,317 1,312,162 421,815 (1,296,982 ) 478,312
2,546,993 2,383,459 2,018,380 (3,964,844 ) 2,983,988
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction - - - 1,043,442 1,043,442
Accumulated deferred income taxes - - 245,223 (245,223 ) -
Accumulated deferred investment tax credits - 34,646 24,176 - 58,822
Asset retirement obligations - 24,274 811,924 - 836,198
Retirement benefits 9,590 56,925 - - 66,515
Property taxes - 25,329 22,766 - 48,095
Lease market valuation liability - 330,457 - - 330,457
Other 18,733 19,605 53,303 - 91,641
28,323 491,236 1,157,392 798,219 2,475,170
$ 4,054,265 $ 5,067,912 $ 4,822,877 $ (3,431,667 ) $ 10,513,387

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
$ 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
$ 3,162,511 $ 4,452,888 $ 4,092,883 $ (3,286,018 ) $ 8,422,264

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Six Months Ended June 30, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)

NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES $ (138,894 ) $ 109,372 $ 82,857 $ (8,316 ) $ 45,019

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt - 276,235 179,500 - 455,735
Short-term borrowings, net 700,000 535,705 416,938 - 1,652,643
Redemptions and Repayments-
Long-term debt (792 ) (285,567 ) (180,334 ) 8,316 (458,377 )
Common stock dividend payment (10,000 ) - - - (10,000 )
Net cash provided from financing activities 689,208 526,373 416,104 8,316 1,640,001

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (20,176 ) (584,151 ) (548,175 ) - (1,152,502 )
Proceeds from asset sales - 10,875 - - 10,875
Sales of investment securities held in trusts - - 384,692 - 384,692
Purchases of investment securities held in trusts - - (404,502 ) - (404,502 )
Loan repayments from (loans to) associated companies, net (530,508 ) - 69,012 - (461,496 )
Other 370 (62,469 ) 12 - (62,087 )
Net cash used for investing activities (550,314 ) (635,745 ) (498,961 ) - (1,685,020 )

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

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Information” in Item 2 above.

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Six Months Ended June 30, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)

NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES $ (77,782 ) $ 255,301 $ 33,686 $ - $ 211,205

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Equity contribution from parent 700,000 700,000 - (700,000 ) 700,000
Short-term borrowings, net 500,000 - - (135,153 ) 364,847
Redemptions and Repayments-
Long-term debt - (616,792 ) (128,744 ) - (745,536 )
Short-term borrowings, net - (135,153 ) - 135,153 -
Common stock dividend payment (37,000 ) - - - (37,000 )
Net cash provided from (used for) financing activities 1,163,000 (51,945 ) (128,744 ) (700,000 ) 282,311

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (9,466 ) (215,804 ) (77,154 ) - (302,424 )
Proceeds from asset sales - 12,120 - - 12,120
Sales of investment securities held in trusts - - 367,924 - 367,924
Purchases of investment securities held in trusts - - (389,286 ) - (389,286 )
Loan repayments from (loans to) associated companies, net (376,444 ) - 192,268 - (184,176 )
Investment in subsidiary (700,000 ) - - 700,000 -
Other 692 328 1,306 - 2,326
Net cash provided from (used for) investing activities (1,085,218 ) (203,356 ) 95,058 700,000 (493,516 )

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

ITEM ~~4T.~~4. CONTROLS AND PROCEDURES ~~– OE, CEI, TE AND PENELEC (Restated)~~

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY

~~In the original Form 10-Q for the second quarter of 2008, each registrant’s~~FirstEnergy’s chief executive officer and chief financial officer ~~concluded that, as~~have reviewed and evaluated the effectiveness of the ~~end of the period covered by that report, the applicable~~ registrant's disclosure controls and procedures were effective as of June 30, 2008. Subsequent to the restatement of the respective registrants’ Consolidated Statements of Cash Flows discussed in the revised Note 1 to the Combined Notes to Consolidated Financial Statements included in the Form 10-Q/A, each registrant's chief executive officer and chief financial officer performed an updated review and evaluated such registrant's disclosure controls and procedures. Based upon that updated evaluation and as a result of the material weakness in the internal controls over the preparation and review of the Consolidated Statement of Cash Flows discussed below, those officers concluded that, as of the end of the period covered by this ~~report, the applicable registrant's disclosure controls and procedures were ineffective as of June 30, 2008.~~

report. 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.

~~As reported in this Form 10-Q/A, each registrant has amended its original Form 10-Q for~~ Based on that evaluation, those officers have concluded that the second quarter of 2008 to restate its Consolidated Statements of Cash Flows for the six months ended June 30, 2008, to correct common stock dividend payments reported in cash flows from financing activities. The Consolidated Statements of Cash Flows for each registrant,registrant's disclosure controls and procedures are effective as originally filed, erroneously did not reflect the payment of common stock dividends in the first and second quarters of 2008, which were declared in the third quarter of 2007. The corrections resulted in a corresponding change in operating liabilities - accounts payable, included in cash flows from operating activities.

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

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

(b) CHANGES IN INTERNAL CONTROLS

During the quarter ended ~~June 30, 2008,~~March 31, 2009, 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 the effectiveness of such registrant's disclosure controls and procedures as of the end of the period covered by this report. 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 as of the end of the period covered by this report.

(b) CHANGES IN INTERNAL CONTROLS

During the quarter ended March 31, 2009, 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.

57128

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 8 and 9 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

FirstEnergy’s Annual Report on Form 10-K for the year ended December 31, 2008 includes a detailed discussion of its risk factors. The information presented below updates certain of those risk factors and should be read in conjunction with the risk factors and information disclosed in FirstEnergy’s Annual Report on Form 10-K.

FES’ Business is Affected By Competitive Procurement Processes Approved by State Regulators

The adoption of competitive bid processes for PLR generation supply in Ohio and Pennsylvania may affect the amount of generation that FES sells to its utility affiliates in those states. For example, the Amended ESP approved by the PUCO established a competitive bid process for generation supply and pricing for a two-year period beginning June 1, 2009 through May 31, 2011. FES intends to participate in the CBP as a supplier and its results of operations and financial condition will be impacted by the price and the percentage of the load for which it is ultimately the supplier.

Competitive Power Markets

FES’ financial performance depends upon its success in competing in wholesale and retail markets in MISO and PJM. FES’ ability to compete successfully in these markets is affected by, among other things, the efficiency and cost structure of its generation fleet, market prices, demand for electricity, effectiveness of risk management practices and the market rules established by state and federal regulators.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock during the first quarter of 2009.

	Period
	January	February	March	First Quarter
Total Number of Shares Purchased (a)	23,535	20,090	887,792	931,417
Average Price Paid per Share	$50.09	$46.20	$41.34	$41.67
Total Number of Shares Purchased
As Part of Publicly Announced Plans
or Programs	-	-	-	-
Maximum Number (or Approximate Dollar
Value) of Shares that May Yet Be
Purchased Under the Plans or Programs	-	-	-	-

(a)

Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan, and shares purchased as part of publicly announced plans.

129

ITEM 6. EXHIBITS

Exhibit Number


OE FirstEnergy
	10.1		Form of Director Indemnification Agreement
	10.2		Form of Management Director Indemnification Agreement
	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
	101*		The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the three months ended March 31, 2009, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.
FES
		4.1	Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, of FirstEnergy Generation Corp. to The Bank of New York Trust Company, N.A., as Trustee
		4.1(a)	First Supplemental Indenture dated as of June 25, 2008 providing among other things for First Mortgage Bonds, Guarantee Series A of 2008 due 2009 and First Mortgage Bonds, Guarantee Series B of 2008 due 2009
		4.1(b)	Second Supplemental Indenture dated as of March 1, 2009 providing among other things for First Mortgage Bonds, Guarantee Series A of 2009 due 2014 and First Mortgage Bonds, Guarantee Series B of 2009 due 2023
		4.1(c)	Third Supplemental Indenture dated as of March 31, 2009 providing among other things for First Mortgage Bonds, Collateral Series A of 2009 due 2011
		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
~~CEI~~		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
TE		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
TE
~~Penelec~~		4.1	First Supplemental Indenture, dated as of April 24, 2009, between the Toledo Edison Company and The Bank of New York Mellon Trust Company, N.A., as trustee to the Indenture dated as of November 1, 2006 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.1)
		4.2	Officer’s Certificate (including the Form of the 7.25% Senior Secured Notes due 2020), dated April 24, 2009 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.2)
		4.3	Fifty-sixth Supplemental Indenture, dated as of April 23, 2009, between The Toledo Edison Company and JPMorgan Chase Bank, N.A., as trustee, to the Indenture of Mortgage and Deed of Trust dated as of April 1, 1947 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.3)
		4.4	Fifty-seventh Supplemental Indenture, dated as of April 24, 2009, between the Toledo Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee, to the Indenture of Mortgage and Deed of Trust dated as of April 1, 1947 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.4)
		4.5	Form of First Mortgage Bonds, 7.25% Series of 2009 Due 2020 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.5)
		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
JCP&L
		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

130

Met-Ed
	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
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-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

* Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited and the purpose of submitting these XBRL-Related Documents is to test the related format and technology and, as a result, investors should not rely on the XBRL-Related Documents in making investment decisions. Furthermore, users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

Pursuant to reporting requirements of respective financings, FirstEnergy, OE, CEI, TE, 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.

58131

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.

~~November 25, 2008~~May 7, 2009

	FIRSTENERGY CORP.
	Registrant

	FIRSTENERGY SOLUTIONS CORP.
	Registrant

	OHIO EDISON COMPANY
	Registrant

	THE CLEVELAND ELECTRIC
	ILLUMINATING COMPANY
	Registrant

	THE TOLEDO EDISON COMPANY
	Registrant

	METROPOLITAN EDISON COMPANY
	Registrant

	PENNSYLVANIA ELECTRIC COMPANY
	Registrant

	/s/ Harvey L. Wagner
	Harvey L. Wagner
	Vice President, Controller
	and ~~Controller~~Chief Accounting Officer

	JERSEY CENTRAL POWER & LIGHT COMPANY
	Registrant



	/s/ Paulette R. Chatman
	Paulette R. Chatman
	Controller
	(Principal Accounting Officer)

59132

Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.

333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

333-145140-01	FIRSTENERGY SOLUTIONS CORP.	31-1560186
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3583	THE TOLEDO EDISON COMPANY	34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

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

1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3522	PENNSYLVANIA ELECTRIC COMPANY	25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

Yes (X) No ( )	FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company
Yes ( ) No (X)	FirstEnergy Solutions Corp.

Large Accelerated Filer ~~( )~~(X)	~~N/A~~FirstEnergy Corp.
Accelerated Filer ( )	N/A
Non-accelerated Filer (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 ~~AUGUST 6, 2008~~May 7, 2009
FirstEnergy Corp., $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	13,628,447
Metropolitan Edison Company, no par value	859,500
Pennsylvania Electric Company, $20 par value	4,427,577

ATSI	American Transmission Systems, ~~Incorporated,~~Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
~~Companies~~	~~OE, CEI, TE, JCP&L, Met-Ed and Penelec~~
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial and other corporate support services
FEV	FirstEnergy Ventures Corp., invests in certain unregulated enterprises and business ventures
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., a public utility holding company
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition Funding	JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds
JCP&L Transition Funding II	JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition bonds
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
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
Shelf Registrants	OE, CEI, TE, JCP&L, Met-Ed and Penelec
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak	A joint venture between FirstEnergy Ventures Corp. and Boich Companies, that owns mining and coal transportation operations near Roundup, Montana
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
Utilities	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
Waverly	The Waverly Power and Light Company, a wholly owned subsidiary of Penelec

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

~~ACO~~	~~Administrative Consent Order~~
AEP	American Electric Power Company, Inc.
ALJ	Administrative Law Judge
~~AMP-Ohio~~	~~American Municipal Power-Ohio, Inc.~~
AOCL	Accumulated Other Comprehensive Loss
AQC	Air Quality Control
~~ARB~~	~~Accounting Research Bulletin~~
~~ARO~~	~~Asset Retirement Obligation~~
~~ASM~~	~~Ancillary Services Market~~
BGS	Basic Generation Service
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CBP	Competitive Bid Process
CO2	Carbon Dioxide
~~DFI~~CTC	~~Demand for Information~~Competitive Transition Charge
DOJ	United States Department of Justice
~~DRA~~DPA	Department of the Public Advocate, Division of ~~Ratepayer Advocate~~
~~EIS~~	~~Energy Independence Strategy~~Rate Counsel
EITF	Emerging Issues Task Force
EMP	Energy Master Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ESP	Electric 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 48	FIN 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109”

		Pages

Glossary of Terms		~~ii-iv~~iii-v

Part I. Financial Information

~~Item~~Items 1. and 2. - Financial ~~Statements.~~Statements and Management’s Discussion and Analysis ofFinancial Condition and Results of Operations.		1

FirstEnergy Corp.

	Management's Discussion and Analysis of Financial Condition and	1-35
	Results of Operations
	Report of Independent Registered Public Accounting Firm	36
	Consolidated Statements of Income	37
	Consolidated Statements of Comprehensive Income	38
	Consolidated Balance Sheets	39
	Consolidated Statements of Cash Flows	40

FirstEnergy Solutions Corp.

	Management's Narrative Analysis of Results of Operations	41-43
	Report of Independent Registered Public Accounting Firm	44
	Consolidated Statements of Income and Comprehensive Income	45
	Consolidated Balance Sheets	46
	Consolidated Statements of Cash Flows	47

Ohio Edison Company

	Management's Narrative Analysis of Results of Operations	48-49
	Report of Independent Registered Public Accounting Firm	250
	Consolidated Statements of Income and Comprehensive Income	351
	Consolidated Balance Sheets	452
	Consolidated Statements of Cash Flows	553

The Cleveland Electric Illuminating Company

	Management's Narrative Analysis of Results of Operations	54-55
	Report of Independent Registered Public Accounting Firm	656
	Consolidated Statements of Income and Comprehensive Income	757
	Consolidated Balance Sheets	858
	Consolidated Statements of Cash Flows	959

The Toledo Edison Company

	Management's Narrative Analysis of Results of Operations	60-61
	Report of Independent Registered Public Accounting Firm	1062
	Consolidated Statements of Income and Comprehensive Income	1163
	Consolidated Balance Sheets	1264
	Consolidated Statements of Cash Flows	1365

~~FIN 47~~	~~FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB~~ ~~Statement No. 143"~~
~~FIN 48~~	~~FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement~~ ~~No. 109”~~
FMB	First Mortgage ~~Bonds~~Bond
FSP	FASB Staff Position
FSP FAS ~~157-2~~107-1 and APB 28-1	FSP FAS ~~157-2, “Effective Date~~107-1 and APB 28-1, “Interim Disclosures about Fair Value of ~~FASB Statement No. 157”~~Financial Instruments”
FSP FAS 115-1 and SFAS 124-1	FSP FAS 115-1 and SFAS 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments”
FSP FAS 115-2 and FAS 124-2	FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments”
FSP FAS 132(R)-1	FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”
FSP FAS 157-4	FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
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
LED	Light-emitting Diode
LIBOR	London Interbank Offered Rate
LOC	Letter of Credit
MEIUG	Met-Ed Industrial Users Group
~~MEW~~	~~Mission Energy Westside, Inc.~~
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service, Inc.
MRO	Market Rate Offer
MW	Megawatts
MWH	Megawatt-hours
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
~~NOPR~~	~~Notice of Proposed Rulemaking~~
NOV	Notice of Violation
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
NYMEX	New York Mercantile Exchange
~~OCA~~OPEB	~~Office of Consumer Advocate~~
~~OTC~~	~~Over the Counter~~Other Post-Employment Benefits
OVEC	Ohio Valley Electric Corporation
~~PCAOB~~	~~Public Company Accounting Oversight Board~~
PCRB	Pollution Control Revenue Bond
PICA	Penelec Industrial Customer Alliance
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last ~~Resort~~Resort; an electric utility’s obligation to provide generation service to customers whose alternative supplier fails to deliver service
PPUC	Pennsylvania Public Utility Commission
~~PRP~~	~~Potentially Responsible Party~~
PSA	Power Supply Agreement
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
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
S&P	Standard & Poor’s Ratings Service
SB221	Amended Substitute Senate Bill 221
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
SFAS	Statement of Financial Accounting Standards

SFAS ~~109~~115	SFAS No. ~~109, “Accounting~~115, "Accounting for ~~Income Taxes”~~
~~SFAS 123(R)~~	~~SFAS No. 123(R), "Share-Based Payment"~~Certain Investments in Debt and Equity Securities"
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 for Asset Retirement Obligations”~~
~~SFAS~~ 157	SFAS No. 157, “Fair Value Measurements”
~~SFAS 159~~	~~SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an~~ ~~Amendment of FASB Statement No. 115”~~
SFAS 160	SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”
~~SFAS 161~~	~~SFAS No 161, “Disclosure about Derivative Instruments and Hedging Activities – an Amendment~~ ~~of FASB Statement No. 133”~~
~~SFAS 162~~	~~SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles”~~
SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
TBC	Transition Bond Charge
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
TSC	Transmission Service Charge
VIE	Variable Interest Entity

Change in Basic Earnings Per Share From Prior Year First Quarter

Basic Earnings Per Share – First Quarter 2008	$ 0.91
Regulatory charges – 2009	(0.55)
Income tax resolution – 2009	0.04
Organizational restructuring – 2009	(0.05)
Gain on non-core asset sales – 2008	(0.06)
Trust securities impairment	(0.04)
Revenues	0.18
Fuel and purchased power	(0.24)
Amortization / deferral of regulatory assets	0.13
Other expenses	0.07
Basic Earnings Per Share – First Quarter 2009	$ 0.39

Electric Distribution KWH Deliveries
Residential	--	%
Commercial	(4.1	) %
Industrial	(17.5	) %
Total Distribution KWH Deliveries	(6.7	) %

Sources of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 3.5% decrease in sales volumes	$	(27	)
Change in prices		49
		22
Wholesale:
Effect of 11.6% decrease in sales volumes		(25	)
Change in prices		(6	)
		(31	)
Net Decrease in Generation Revenues	$	(9	)

OE

	Six Months
	Ended June 30, 2008
	As Previously			As
	Reported			Restated
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	92,751		$	92,751
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		42,907			42,907
Amortization of regulatory assets		96,394			96,394
Deferral of new regulatory assets		(51,312	)		(51,312	)
Amortization of lease costs		(4,399	)		(4,399	)
Deferred income taxes and investment tax credits, net		7,059			7,059
Accrued compensation and retirement benefits		(31,579	)		(31,579	)
Decrease (increase) in operating assets-
Receivables		30,159			30,159
Prepayments and other current assets		(2,485	)		(2,485	)
Decrease in operating liabilities-
Accounts payable		(56,831	)		(6,831	)
Accrued taxes		(31,306	)		(31,306	)
Accrued interest		(1,252	)		(1,252	)
Electric service prepayment programs		(21,771	)		(21,771	)
Other		2,671			2,671
Net cash provided from operating activities		71,006			121,006

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		69,573			69,573
Redemptions and Repayments-
Long-term debt		(175,577	)		(175,577	)
Dividend Payments-
Common stock		-			(50,000	)
Net cash used for financing activities		(106,004	)		(156,004	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(92,061	)		(92,061	)
Sales of investment securities held in trusts		79,613			79,613
Purchases of investment securities held in trusts		(84,130	)		(84,130	)
Loan repayments from associated companies, net		123,905			123,905
Cash investments		5,000			5,000
Other		2,828			2,828
Net cash provided from investing activities		35,155			35,155

Net increase in cash and cash equivalents	$	157		$	157

	Three Months				Six Months
	Ended June 30				Ended June 30
Reconciliation of Basic and Diluted Earnings per Share	2008		2007		2008		2007
	(In millions, except per share amounts)

Net income	$	263	$	338	$	539	$	628

Average shares of common stock outstanding – Basic		304		304		304		309
Assumed exercise of dilutive stock options and awards		3		4		3		4
Average shares of common stock outstanding – Dilutive		307		308		307		313

Basic earnings per share	$	0.86	$	1.11	$	1.77	$	2.03
Diluted earnings per share	$	0.85	$	1.10	$	1.75	$	2.01

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

Liabilities:
Derivatives	$	-	$	123	$	-	$	123
NUG contracts(3)		-		-		644		644
Total	$	-	$	123	$	644	$	767

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

Balance, April 1, 2007	$	1,208		$	772		$	89	$	2	$	27	$	86	$	153	$	78
Liabilities incurred		-			-			-		-		-		-		-		-
Liabilities settled		-			-			-		-		-		-		-		-
Accretion		21			13			2		-		-		1		3		1
Revisions in estimated cash flows		(1	)		(1	)		-		-		-		-		-		-
Balance, June 30, 2007	$	1,228		$	784		$	91	$	2	$	27	$	87	$	156	$	79

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

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended June 30, 2008	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)

REVENUES	$	1,064,627		$	565,225		$	287,028		$	(845,602	)	$	1,071,278

EXPENSES:
Fuel		3,605			277,192			29,753			-			310,550
Purchased power from non-affiliates		220,339			-			-			-			220,339
Purchased power from affiliates		842,670			2,932			34,528			(845,602	)		34,528
Other operating expenses		29,842			124,173			121,534			12,189			287,738
Provision for depreciation		1,600			30,027			25,893			(1,360	)		56,160
General taxes		4,727			11,504			3,564			-			19,795
Total expenses		1,102,783			445,828			215,272			(834,773	)		929,110

OPERATING INCOME (LOSS)		(38,156	)		119,397			71,756			(10,829	)		142,168

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		98,590			489			(9,449	)		(91,704	)		(2,074	)
Interest expense - affiliates		(50	)		(7,920	)		(2,758	)		-			(10,728	)
Interest expense - other		(6,663	)		(23,697	)		(10,632	)		16,487			(24,505	)
Capitalized interest		28			9,856			657			-			10,541
Total other income (expense)		91,905			(21,272	)		(22,182	)		(75,217	)		(26,766	)

INCOME BEFORE INCOME TAXES		53,749			98,125			49,574			(86,046	)		115,402

INCOME TAXES (BENEFIT)		(14,345	)		38,467			20,838			2,348			47,308

NET INCOME	$	68,094		$	59,658		$	28,736		$	(88,394	)	$	68,094

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of June 30, 2008	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	-	$	-	$	-		$	2
Receivables-
Customers		117,858		-		-		-			117,858
Associated companies		419,402		259,454		80,249		(285,131	)		473,974
Other		1,475		1,376		5,105		-			7,956
Notes receivable from associated companies		554,279		-		-		-			554,279
Materials and supplies, at average cost		2,942		281,275		205,327		-			489,544
Prepayments and other		141,414		30,300		695		-			172,409
		1,237,372		572,405		291,376		(285,131	)		1,816,022

PROPERTY, PLANT AND EQUIPMENT:
In service		82,280		5,385,410		4,666,202		(391,896	)		9,741,996
Less - Accumulated provision for depreciation		9,411		2,684,494		1,609,851		(169,476	)		4,134,280
		72,869		2,700,916		3,056,351		(222,420	)		5,607,716
Construction work in progress		11,373		1,064,083		145,833		-			1,221,289
		84,242		3,764,999		3,202,184		(222,420	)		6,829,005
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,234,635		-			1,234,635
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		2,677,674		-		-		(2,677,674	)		-
Other		2,323		63,467		202		-			65,992
		2,679,997		63,467		1,297,737		(2,677,674	)		1,363,527
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		16,722		480,721		-		(249,475	)		247,968
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		3,211		12,206		-		-			15,417
Unamortized sale and leaseback costs		-		23,282		-		50,096			73,378
Other		8,473		58,569		8,813		(47,063	)		28,792
		52,654		667,041		31,580		(246,442	)		504,833
	$	4,054,265	$	5,067,912	$	4,822,877	$	(3,431,667	)	$	10,513,387
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	4,679	$	873,562	$	1,077,289	$	(17,315	)	$	1,938,215
Short-term borrowings-
Associated companies		-		774,490		442,217		-			1,216,707
Other		1,000,000		-		-		-			1,000,000
Accounts payable-
Associated companies		275,820		253,818		93,599		(275,431	)		347,806
Other		81,252		133,486		-		-			214,738
Accrued taxes		1,162		58,976		19,393		(6,993	)		72,538
Other		116,036		98,885		14,607		34,697			264,225
		1,478,949		2,193,217		1,647,105		(265,042	)		5,054,229
CAPITALIZATION:
Common stockholder's equity		2,505,676		1,071,297		1,596,565		(2,667,862	)		2,505,676
Long-term debt and other long-term obligations		41,317		1,312,162		421,815		(1,296,982	)		478,312
		2,546,993		2,383,459		2,018,380		(3,964,844	)		2,983,988
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,043,442			1,043,442
Accumulated deferred income taxes		-		-		245,223		(245,223	)		-
Accumulated deferred investment tax credits		-		34,646		24,176		-			58,822
Asset retirement obligations		-		24,274		811,924		-			836,198
Retirement benefits		9,590		56,925		-		-			66,515
Property taxes		-		25,329		22,766		-			48,095
Lease market valuation liability		-		330,457		-		-			330,457
Other		18,733		19,605		53,303		-			91,641
		28,323		491,236		1,157,392		798,219			2,475,170
	$	4,054,265	$	5,067,912	$	4,822,877	$	(3,431,667	)	$	10,513,387