ToTotal expenses decreased $62 million in the ~~Stockholder and Board~~second quarter of

~~Directors of The Toledo Edison Company:~~ 2009 due to the following factors:

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

·	Fuel costs decreased $40 million due to decreased generation volumes ($70 million) partially offset by higher unit prices ($30 million). The increased unit prices, which are expected to continue for the remainder of 2009, primarily reflect higher costs for eastern coal.

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.

·	Purchased power costs decreased $35 million due primarily to lower unit costs ($34 million) and lower volume requirements ($1 million).

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.

·	Fossil operating costs decreased $28 million due to a reduction in contractor and material costs ($18 million) and lower labor and employee benefit expenses ($10 million), reflecting FirstEnergy’s cost control initiatives.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report 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.

·	Nuclear operating costs decreased $7 million due to lower labor and employee benefit expenses, partially offset by higher expenses associated with the 2009 Perry and Beaver Valley refueling outages and the Davis-Besse maintenance outage.

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

·	Other operating expenses increased $22 million due primarily to increased intersegment billings for leasehold costs from the Ohio Companies.

·	Transmission expense increased $17 million due primarily to increased net congestion and loss expenses in PJM.


~~PricewaterhouseCoopers LLP~~ ~~Cleveland, Ohio~~ ~~May 7, 2008, except as~~ ·	Higher depreciation expense of $9 million was due primarily to ~~the error correction described~~NGC's increased ownership interests in ~~Note 1,~~ ~~which is as~~Perry and Beaver Valley Unit 2 following its purchase of ~~November 24, 2008.~~ lease equity interests.

Other Expense –

Total other expense in the second quarter of 2009 was $24 million lower than the second quarter of 2008, primarily due to a $16 million decrease in trust securities impairments and a $10 million decrease in interest expense (net of capitalized interest).

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

Net income for this segment increased to $21 million in the second quarter of 2009 from $20 million in the same period of 2008. Higher generation revenues and lower operating expenses were partially offset by higher purchased power costs.

Revenues –

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

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Ended
March 31,

2008 2007
(In thousands)

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

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

OPERATING INCOME 26,134 40,252

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

INCOME BEFORE INCOME TAXES 25,103 36,957

INCOME TAXES 8,088 11,097

NET INCOME 17,015 25,860

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

TOTAL COMPREHENSIVE INCOME $ 18,185 $ 26,478

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

	Three Months
	Ended June 30
Revenues by Type of Service	2009		2008		Increase (Decrease)
	(In millions)
Generation sales:
Retail	$	796	$	587	$	209
Wholesale		-		3		(3	)
Total generation sales		796		590		206
Transmission		71		93		(22	)
Other		1		-		1
Total Revenues	$	868	$	683	$	185

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 4.4% increase in sales volumes	$	26
Change in prices		183
Total Increase in Retail Generation Revenues	$	209

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 following the expiration of certain government aggregation programs in Ohio. Average prices increased primarily due to an increase in the Ohio Companies' fuel cost recovery rider that was effective from January through May 2009. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under the Ohio Companies' CBP.

Decreased transmission revenue of $22 million resulted from the termination of the transmission tariff (as discussed above) and reduced MISO revenues, partially offset by higher sales volumes. The difference between transmission revenues accrued and transmission costs incurred is deferred, resulting in no material impact to current period earnings.

Expenses -

Purchased power costs were $258 million higher due primarily to higher unit costs and volumes. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power	Increase
	(In millions)

Change due to increased unit costs	$	239
Change due to increased volumes		19
	$	258

The increase in purchased volumes was due to the higher retail generation sales requirements described above. The higher unit costs reflect the results of the Ohio Companies' power supply procurement processes for retail customers during the second quarter of 2009 (see Regulatory Matters – Ohio).

Other operating expenses decreased $67 million due to lower MISO transmission-related expenses ($43 million) and increased intersegment credits related to the Ohio Companies' generation leasehold interests. The amortization of regulatory assets increased by $38 million in the second quarter of 2009 due primarily to increased MISO transmission cost amortization. The deferral of new regulatory assets increased by $45 million due to CEI’s deferral of purchased power costs as approved by the PUCO.

THE TOLEDO EDISON COMPANY

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

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

Summary of Results of Operations – First Six Months of 2009 Compared with the First Six Months of 2008

Financial results for FirstEnergy's major business segments in the first six months of 2009 and 2008 were as follows:

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Six Months 2009 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	3,756		$	485		$	1,762		$	-		$	6,003
Other		277			354			18			(47	)		602
Internal		-			1,732			-			(1,732	)		-
Total Revenues		4,033			2,571			1,780			(1,779	)		6,605

Expenses:
Fuel		-			588			-			-			588
Purchased power		1,842			346			1,711			(1,732	)		2,167
Other operating expenses		794			670			32			(57	)		1,439
Provision for depreciation		219			132			-			11			362
Amortization of regulatory assets		547			-			95			-			642
Deferral of new regulatory assets		-			-			(136	)		-			(136	)
General taxes		320			57			4			14			395
Total Expenses		3,722			1,793			1,706			(1,764	)		5,457

Operating Income		311			778			74			(15	)		1,148
Other Income (Expense):
Investment income		64			(23	)		1			(26	)		16
Interest expense		(225	)		(60	)		-			(115	)		(400	)
Capitalized interest		2			24			-			35			61
Total Other Expense		(159	)		(59	)		1			(106	)		(323	)

Income Before Income Taxes		152			719			75			(121	)		825
Income taxes		61			288			30			(77	)		302
Net Income		91			431			45			(44	)		523
Less: Noncontrolling interest income (loss)		-			-			-			(10	)		(10	)
Earnings available to FirstEnergy Corp.	$	91		$	431		$	45		$	(34	)	$	533

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
Restated
2008 2007
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 17,015 $ 25,860
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 9,025 9,117
Amortization of regulatory assets 25,025 23,876
Deferral of new regulatory assets (9,494 ) (13,481 )
Deferred rents and lease market valuation liability 6,099 (10,891 )
Deferred income taxes and investment tax credits, net (3,404 ) (3,639 )
Accrued compensation and retirement benefits (1,813 ) (756 )
Pension trust contribution - (7,659 )
Decrease in operating assets-
Receivables 45,738 158
Prepayments and other current assets 181 312
Increase (decrease) in operating liabilities-
Accounts payable (174,243 ) (17,533 )
Accrued taxes 6,840 9,379
Accrued interest 4,663 3,951
Electric service prepayment programs (2,670 ) (2,616 )
Other 991 (541 )
Net cash provided from (used for) operating activities (76,047 ) 15,537

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net 52,821 -
Redemptions and Repayments-
Long-term debt (9 ) -
Short-term borrowings, net - (46,518 )
Dividend Payments-
Common stock (15,000 ) -
Net cash provided from (used for) financing activities 37,812 (46,518 )

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

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

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

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Six Months 2008 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	4,080		$	613		$	1,361		$	-		$	6,054
Other		314			91			29			34			468
Internal		-			1,480			-			(1,480	)		-
Total Revenues		4,394			2,184			1,390			(1,446	)		6,522

Expenses:
Fuel		1			643			-			-			644
Purchased power		1,980			427			1,143			(1,480	)		2,070
Other operating expenses		858			621			158			(57	)		1,580
Provision for depreciation		210			112			-			10			332
Amortization of regulatory assets		484			-			20			-			504
Deferral of new regulatory assets		(198	)		-			(5	)		-			(203	)
General taxes		322			56			3			14			395
Total Expenses		3,657			1,859			1,319			(1,513	)		5,322

Operating Income		737			325			71			67			1,200
Other Income (Expense):
Investment income		85			(14	)		-			(38	)		33
Interest expense		(203	)		(72	)		-			(92	)		(367	)
Capitalized interest		1			17			-			3			21
Total Other Expense		(117	)		(69	)		-			(127	)		(313	)

Income Before Income Taxes		620			256			71			(60	)		887
Income taxes		248			103			28			(32	)		347
Net Income		372			153			43			(28	)		540
Less: Noncontrolling interest income		-			-			-			1			1
Earnings available to FirstEnergy Corp.	$	372		$	153		$	43		$	(29	)	$	539


Changes Between First Six Months 2009
and First Six Months 2008
Financial Results Increase (Decrease)

Revenues:
External
Electric	$	(324	)	$	(128	)	$	401		$	-		$	(51	)
Other		(37	)		263			(11	)		(81	)		134
Internal		-			252			-			(252	)		-
Total Revenues		(361	)		387			390			(333	)		83

Expenses:
Fuel		(1	)		(55	)		-			-			(56	)
Purchased power		(138	)		(81	)		568			(252	)		97
Other operating expenses		(64	)		49			(126	)		-			(141	)
Provision for depreciation		9			20			-			1			30
Amortization of regulatory assets		63			-			75			-			138
Deferral of new regulatory assets		198			-			(131	)		-			67
General taxes		(2	)		1			1			-			-
Total Expenses		65			(66	)		387			(251	)		135

Operating Income		(426	)		453			3			(82	)		(52	)
Other Income (Expense):
Investment income		(21	)		(9	)		1			12			(17	)
Interest expense		(22	)		12			-			(23	)		(33	)
Capitalized interest		1			7			-			32			40
Total Other Expense		(42	)		10			1			21			(10	)

Income Before Income Taxes		(468	)		463			4			(61	)		(62	)
Income taxes		(187	)		185			2			(45	)		(45	)
Net Income		(281	)		278			2			(16	)		(17	)
Less: Noncontrolling interest income		-			-			-			(11	)		(11	)
Earnings available to FirstEnergy Corp.	$	(281	)	$	278		$	2		$	(5	)	$	(6	)

Energy Delivery Services – First Six Months of 2009 Compared to First Six Months of 2008

~~Report~~Net income decreased $281 million to $91 million in the first six months of ~~Independent Registered Public Accounting Firm~~2009 compared to $372 million in the first six months of 2008, primarily due to decreased revenues and increased amortization of regulatory assets, partially offset by lower purchased power and other operating expenses.

Revenues –

The decrease in total revenues resulted from the following sources:

	Six Months
	Ended June 30				Increase
Revenues by Type of Service	2009		2008		(Decrease)
	(In millions)
Distribution services	$	1,662	$	1,874	$	(212	)
Generation sales:
Retail		1,531		1,562		(31	)
Wholesale		349		471		(122	)
Total generation sales		1,880		2,033		(153	)
Transmission		396		393		3
Other		95		94		1
Total Revenues	$	4,033	$	4,394	$	(361	)

ToThe decrease in distribution deliveries by customer class are summarized in the ~~Stockholder and Board of~~

~~Directors of Pennsylvania Electric Company:~~following table:

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

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

Electric Distribution KWH Deliveries
~~PricewaterhouseCoopers LLP~~ Residential			~~Cleveland, Ohio~~ (1.3) %
~~May 7, 2008, except as to the error correction described in Note 1,~~ Commercial			~~which is as of November 24, 2008.~~ (3.9) %
Industrial			(19.2) %
Total Distribution KWH Deliveries			(8.0) %

The lower revenues from distribution deliveries were driven by the reductions in sales volume. The decreases in distribution deliveries to commercial and industrial customers were primarily due to economic conditions in FirstEnergy's service territory. In the industrial sector, KWH deliveries declined to major automotive (31.5%) and steel (45.4%). Transition charges for OE and TE that ceased effective January 1, 2009 with the full recovery of related costs and the transition rate reduction for CEI effective June 1, 2009, were offset by PUCO-approved distribution rate increases (see Regulatory Matters – Ohio).

The following table summarizes the price and volume factors contributing to the $153 million decrease in generation revenues in the first six months of 2009 compared to the same period of 2008:

	Increase
Sources of Change in Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 6.3% decrease in sales volumes	$	(98	)
Change in prices		67
		(31	)
Wholesale:
Effect of 12.2% decrease in sales volumes		(57	)
Change in prices		(65	)
		(122	)
Net Decrease in Generation Revenues	$	(153	)

The decrease in retail generation sales volumes was primarily due to weakened economic conditions and reduced weather-related usage. Cooling degree days decreased by 23% in the first six months of 2009, while heating degree days increased by 2% compared to the same period last year. The increase in retail generation prices during the first six months of 2009 was due to higher generation rates for JCP&L and Penn under their power procurement processes. Wholesale generation sales decreased principally as a result of JCP&L selling less available power from NUGs due to the termination of a NUG purchase contract in October 2008. The decrease in wholesale prices reflected lower spot market prices in PJM.

Transmission revenues increased $3 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the annual updates to their TSC riders. Met-Ed and Penelec defer the difference between revenues from their transmission riders and transmission costs incurred with no material effect on current period earnings (see Regulatory Matters – Pennsylvania).

Expenses –

Total expenses increased by $65 million due to the following:

Purchased power costs were $138 million lower in the first six months of 2009 due to lower volumes, partially offset by higher unit costs and an increase in the amount of NUG costs deferred. The increased unit costs primarily reflected the effect of higher JCP&L costs resulting from its BGS auction process. The following table summarizes the sources of changes in purchased power costs:

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Ended
March 31,

2008 2007

(In thousands)

REVENUES:
Electric sales $ 376,028 $ 339,226
Gross receipts tax collections 19,464 16,680
Total revenues 395,492 355,906

EXPENSES:
Purchased power 221,234 200,842
Other operating costs 71,077 59,461
Provision for depreciation 12,516 11,777
Amortization of regulatory assets 16,346 15,394
Deferral of new regulatory assets (3,526 ) (17,088 )
General taxes 21,855 19,851
Total expenses 339,502 290,237

OPERATING INCOME 55,990 65,669

OTHER INCOME (EXPENSE):
Miscellaneous income (expense) (191 ) 1,417
Interest expense (15,322 ) (11,337 )
Capitalized interest (806 ) 258
Total other expense (16,319 ) (9,662 )

INCOME BEFORE INCOME TAXES 39,671 56,007

INCOME TAXES 18,279 24,263

NET INCOME 21,392 31,744

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (3,473 ) (2,825 )
Unrealized gain on derivative hedges 16 16
Change in unrealized gain on available-for-sale securities 11 (3 )
Other comprehensive loss (3,446 ) (2,812 )
Income tax benefit related to other comprehensive loss (1,506 ) (1,298 )
Other comprehensive loss, net of tax (1,940 ) (1,514 )

TOTAL COMPREHENSIVE INCOME $ 19,452 $ 30,230

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

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	163
Change due to decreased volumes		(266	)
		(103	)
Purchases from FES:
Change due to decreased unit costs		(16	)
Change due to increased volumes		37
		21

Increase in NUG costs deferred		(56	)
Net Decrease in Purchased Power Costs	$	(138	)

PJM transmission expenses were lower by $81 million, resulting primarily from reduced volumes and congestion costs.

An increase in other operating expense of $32 million resulted from recognition of economic development and energy efficiency obligations in accordance with the PUCO-approved ESP.

A reduction in contractor and material expenses of $21 million, reflecting more costs dedicated to capital projects compared to the prior year, was partially offset by an increase from organizational restructuring costs of $5 million.

A $63 million increase in the amortization of regulatory assets was due primarily to the ESP-related impairment of CEI’s regulatory assets and PJM transmission cost amortization in the first six months of 2009, partially offset by the cessation of transition cost amortizations for OE and TE.

A $198 million decrease in the deferral of new regulatory assets was principally due to the absence of PJM transmission cost deferrals and RCP distribution cost deferrals by the Ohio Companies.

Depreciation expense increased $9 million due to property additions since the second quarter of 2008.

General taxes decreased $2 million due to lower gross receipts and excise taxes.

Other Expense –

Other expense increased $42 million in the first six months of 2009 compared to 2008. Lower investment income of $21 million resulted primarily from repaid notes receivable from affiliates since the second quarter of 2008. Higher interest expense (net of capitalized interest) of $21 million was related to the senior notes issuances of JCP&L and Met-Ed in January 2009 and TE in April 2009.

Competitive Energy Services – First Six Months of 2009 Compared to First Six Months of 2008

Net income increased to $431 million in the first six months of 2009 compared to $153 million in the same period in 2008. The increase in net income includes FGCO's $252 million gain from the sale of 9% of its participation in OVEC ($158 million after tax) and an increase in gross sales margins, partially offset by higher other operating costs.

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2008 2007
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 43 $ 46
Receivables-
Customers (less accumulated provisions of $4,201,000 and $3,905,000,
respectively, for uncollectible accounts) 141,316 137,455
Associated companies 23,396 22,014
Other 28,833 19,529
Notes receivable from associated companies 16,923 16,313
Prepaid gross receipts taxes 41,242 -
Other 2,426 3,077
254,179 198,434
UTILITY PLANT:
In service 2,230,667 2,219,002
Less - Accumulated provision for depreciation 843,500 838,621
1,387,167 1,380,381
Construction work in progress 33,727 24,251
1,420,894 1,404,632
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts 132,152 137,859
Non-utility generation trusts 113,958 112,670
Other 536 531
246,646 251,060
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 777,616 777,904
Pension assets 69,405 66,111
Other 29,770 33,893
876,791 877,908
$ 2,798,510 $ 2,732,034
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Short-term borrowings-
Associated companies $ 183,102 $ 214,893
Other 150,000 -
Accounts payable-
Associated companies 61,476 83,359
Other 50,516 51,777
Accrued taxes 9,302 15,111
Accrued interest 13,677 13,167
Other 23,330 25,311
491,403 403,618
CAPITALIZATION:
Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
4,427,577 shares outstanding 88,552 88,552
Other paid-in capital 920,265 920,616
Accumulated other comprehensive income 3,006 4,946
Retained earnings 79,336 57,943
Total common stockholder's equity 1,091,159 1,072,057
Long-term debt and other long-term obligations 732,465 777,243
1,823,624 1,849,300
NONCURRENT LIABILITIES:
Regulatory liabilities 67,347 73,559
Accumulated deferred income taxes 220,500 210,776
Retirement benefits 41,644 41,298
Asset retirement obligations 83,129 81,849
Other 70,863 71,634
483,483 479,116
COMMITMENTS AND CONTINGENCIES (Note 10)
$ 2,798,510 $ 2,732,034

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

Total revenues increased $387 million in the first six months of 2009 compared to the same period in 2008. This increase primarily resulted from the OVEC sale and higher unit prices on affiliated generation sales to the Ohio Companies and non-affiliated customers, partially offset by lower sales volumes.

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

	Six Months
	Ended June 30				Increase
Revenues by Type of Service	2009		2008		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	174	$	315	$	(141	)
Wholesale		311		298		13
Total Non-Affiliated Generation Sales		485		613		(128	)
Affiliated Generation Sales		1,732		1,480		252
Transmission		41		66		(25	)
Sale of OVEC participation interest		252		-		252
Other		61		25		36
Total Revenues	$	2,571	$	2,184	$	387

The lower retail revenues resulted from the expiration of government aggregation programs in Ohio at the end of 2008 that were supplied by FES, partially offset by increased revenue from both the PJM and MISO markets. The increase in MISO retail sales is primarily the result of the acquisition of new customers and higher unit prices. The increase in PJM retail sales resulted from higher unit prices. As of August 1, 2009, FES has signed new government aggregation contracts with 50 communities that will provide discounted generation prices to approximately 600,000 residential and small commercial customers. The retail sales volumes associated with these new contracts are expected to result in an increased level of retail revenues in the second half of 2009 as compared to results for the period ended June 30, 2009.

Higher non-affiliated wholesale revenues resulted from higher capacity prices in PJM and increased sales volumes and favorable settlements on hedged transactions in MISO, partially offset by decreased sales volumes and spot market prices in PJM. The increased affiliated company generation revenues were due to higher unit prices to the Ohio Companies and increased sales volumes to Met-Ed and Penelec, partially offset by lower sales volumes to the Ohio Companies. The higher unit prices reflected the results of the Ohio Companies' power procurement processes in the first half of 2009 (see Regulatory Matters – Ohio). The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements, partially offset by lower sales to Penn due to decreased default service requirements in the first six months of 2009 compared to the first six months of 2008.

In the first quarter of 2009, FES supplied approximately 75% of the Ohio Companies’ power requirements as one of four winning bidders in the Ohio Companies' RFP process. In the second quarter of 2009, FES supplied 100% of the power for the Ohio Companies’ PLR service in April and May 2009, and approximately 56% of the Ohio Companies' supply needs in June 2009. Subsequent to the Ohio Companies’ CBP, FES purchased additional tranches from other winning bidders and effective August 1, 2009, FES will supply 62% of the Ohio Companies’ PLR generation requirements.

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

	Increase
Source of Change in Non-Affiliated Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 57.8% decrease in sales volumes	$	(182	)
Change in prices		41
		(141	)
Wholesale:
Effect of 4.1% decrease in sales volumes		(12	)
Change in prices		25
		13
Net Decrease in Non-Affiliated Generation Revenues	$	(128	)

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
Restated
2008 2007
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 21,392 $ 31,744
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 12,516 11,777
Amortization of regulatory assets 16,346 15,394
Deferral of new regulatory assets (3,526 ) (17,088 )
Deferred costs recoverable as regulatory assets (8,403 ) (18,433 )
Deferred income taxes and investment tax credits, net 10,541 13,366
Accrued compensation and retirement benefits (10,488 ) (8,786 )
Cash collateral 301 1,450
Pension trust contribution - (13,436 )
Increase in operating assets-
Receivables (13,701 ) (30,050 )
Prepayments and other current assets (40,591 ) (36,225 )
Increase (Decrease) in operating liabilities-
Accounts payable (3,144 ) (46,168 )
Accrued taxes (5,809 ) (9,152 )
Accrued interest 510 5,518
Other 4,991 3,920
Net cash used for operating activities (19,065 ) (96,169 )

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net 118,209 119,361
Redemptions and Repayments
Long-term debt (45,112 ) -
Dividend Payments-
Common stock (20,000 ) -
Net cash provided from financing activities 53,097 119,361

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (28,902 ) (20,404 )
Sales of investment securities held in trusts 24,407 12,758
Purchases of investment securities held in trusts (29,083 ) (15,509 )
Loan repayments from (loans to) associated companies, net (610 ) 708
Other 153 (747 )
Net cash used for investing activities (34,035 ) (23,194 )

Net decrease in cash and cash equivalents (3 ) (2 )
Cash and cash equivalents at beginning of period 46 44
Cash and cash equivalents at end of period $ 43 $ 42

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

	Increase
Source of Change in Affiliated Generation Revenues	(Decrease)
	(In millions)
Ohio Companies:
Effect of 19.2% decrease in sales volumes	$	(218	)
Change in prices		449
		231
Pennsylvania Companies:
Effect of 10.6% increase in sales volumes		37
Change in prices		(16	)
		21
Net Increase in Affiliated Generation Revenues	$	252

Transmission revenues decreased $25 million due primarily to reduced retail loads in MISO. Other revenue increased $36 million primarily due to rental income associated with NGC's acquisition of additional equity interests in the Perry and Beaver Valley Unit 2 leases.

Expenses -

Total expenses decreased $66 million in the first six months of 2009 due to the following factors:

Purchased power costs decreased $81 million due to lower volume ($103 million), partially offset by higher unit prices ($22 million) that resulted from higher capacity costs.

Fuel costs decreased $55 million due to lower generation volumes ($116 million) partially offset by higher unit prices ($61 million). The higher unit prices, which are expected to continue for the remainder of 2009, primarily reflect increased costs for eastern coal.

Fossil operating costs decreased $32 million due to a $24 million reduction in contractor and material costs that resulted from reduced maintenance activities and more labor dedicated to capital projects compared to the prior year.

Other expense increased $49 million due primarily to increased intersegment billings for leasehold costs from the Ohio Companies.

Transmission expense increased $24 million due primarily to increased net congestion and loss expenses in PJM.

Higher depreciation expense of $20 million was due to NGC's increased ownership interest in Beaver Valley Unit 2 and Perry.

Nuclear operating costs increased $9 million in the first six months of 2009 due to an additional refueling outage during the 2009 period.

Other Expense –

Total other expense in the first six months of 2009 was $10 million lower than the first six months of 2009, primarily due to a decline in interest expense (net of capitalized interest) of $19 million from the repayment of notes payable to affiliates, partially offset by an $8 million decrease in earnings from nuclear decommissioning trust investments resulting from securities impairments.

Ohio Transitional Generation Services – First Six Months of 2009 Compared to First Six Months of 2008

Net income for this segment increased to $45 million in the first six months of 2009 from $43 million in the same period of 2008. Higher generation revenues, lower operating expenses and increased deferrals of regulatory assets were partially offset by higher purchased power expenses.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~1. ORGANIZATION AND BASIS OF PRESENTATION~~Revenues –

~~FirstEnergy is a diversified energy company that holds, directly or indirectly, all of~~The increase in reported segment revenues resulted from 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.~~following sources:

~~FirstEnergy~~

	Six Months
	Ended June 30
Revenues by Type of Service	2009		2008		Increase (Decrease)
	(In millions)
Generation sales:
Retail	$	1,597	$	1,193	$	404
Wholesale		-		5		(5	)
Total generation sales		1,597		1,198		399
Transmission		181		186		(5	)
Other		2		6		(4	)
Total Revenues	$	1,780	$	1,390	$	390

The following table summarizes the price and ~~its subsidiaries follow GAAP~~volume factors contributing to the net increase in sales revenues from retail customers:

Source of Change in Generation Revenues	Increase
	(In millions)
Retail:
Effect of 4.7% increase in sales volumes	$	56
Change in prices		348
Net Increase in Retail Generation Revenues	$	404

The increase in generation sales volume in the first six months of 2009 was primarily due to reduced customer shopping, reflecting the return of customers to PLR service following the expiration of certain government aggregation programs in Ohio in 2008. This increased sales volume was partially offset by lower sales due to milder weather and ~~comply with~~economic conditions in the ~~regulations, orders, policies and practices prescribed by~~Ohio Companies' service territory. Average prices increased primarily due to an increase in the ~~SEC,~~Ohio Companies' fuel cost recovery riders that were effective from January through May 2009. Effective June 1, 2009, the ~~FERC and, as applicable, the PUCO, the PPUC~~transmission tariff ended and the ~~NJBPU. The preparation~~recovery 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~~transmission costs is included in the ~~combined Annual Report on Form 10-K for~~generation rate established under the ~~year ended December 31, 2007 for FirstEnergy, FES and~~Ohio Companies' CBP.

Decreased transmission revenue of $5 million resulted from the ~~Companies. The consolidated unaudited financial statements of FirstEnergy, FES and each~~termination of the ~~Companies reflect all normal recurring adjustments that,~~transmission tariff and lower MISO revenues partially offset by higher sales volumes. The difference between transmission revenues accrued and transmission costs incurred is deferred, resulting in no material impact to current period earnings.

Expenses -

Purchased power costs were $568 million higher due primarily to higher unit costs for power. The factors contributing to the higher costs are summarized in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 8) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.following table:

Source of Change in Purchased Power	Increase
	(In millions)

Change due to increased unit costs	$	523
Change due to increased volumes		45
		568

The consolidated financial statements as of March 31, 2008 and for the three-month periods ended March 31, 2008 and 2007 have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated May 7, 2008, except asincrease in purchased volumes was due to the ~~error correction~~higher retail generation sales requirements described ~~in Note 1, which is as of November 24, 2008) is included herein.~~above. The ~~report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly,~~higher unit costs reflect the ~~degree of reliance on their report on such information should be restricted in light~~results of the ~~limited nature~~Ohio Companies' power supply procurement processes for retail customers during the first six months of ~~the review procedures applied. PricewaterhouseCoopers LLP is not subject~~2009 (see Regulatory Matters – Ohio).

Other operating expenses decreased $126 million due to lower MISO transmission expenses ($71 million) and associated company cost reimbursements related to the ~~liability provisions~~Ohio Companies' generation leasehold interests. The amortization 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 certifiedregulatory assets increased 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 three months ended March 31, 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$75 million in the first ~~quarter~~six months of ~~2008, which were declared in~~2009 due primarily to increased MISO transmission cost amortization. The deferral of new regulatory assets increased by $131 million due to CEI’s deferral of purchased power costs as approved by 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 ended March 31, 2008 and consolidated balance sheets as of March 31, 2008 contained in the combined Form 10-Q for the quarter ended March 31, 2008, as originally filed on May 8, 2008.

~~The effects of the corrections on OE’s, CEI’s, TE’s and Penelec’s Consolidated Statements of Cash Flows for the three months ended March 31, 2008 are as follows:~~

PUCO.

Other – First Six Months of 2009 Compared to First Six Months of 2008

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 $5 million decrease in FirstEnergy's net income in the first six 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.

As of June 30, 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 June 30, 2009, included the following (in millions):

OE

Three Months
Ended March 31, 2008
As Previously As
Reported Restated
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 43,909 $ 43,909
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 21,493 21,493
Amortization of regulatory assets 48,538 48,538
Deferral of new regulatory assets (25,411 ) (25,411 )
Amortization of lease costs 32,934 32,934
Deferred income taxes and investment tax credits, net 6,866 6,866
Accrued compensation and retirement benefits (19,482 ) (19,482 )
Increase in operating assets-
Receivables (27,496 ) (27,496 )
Prepayments and other current assets (7,451 ) (7,451 )
Increase (decrease) in operating liabilities-
Accounts payable (18,939 ) (3,939 )
Accrued taxes 2,991 2,991
Accrued interest (5,919 ) (5,919 )
Electric service prepayment programs (10,028 ) (10,028 )
Other (2,066 ) (2,066 )
Net cash provided from operating activities 39,939 54,939

CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt (80 ) (80 )
Dividend Payments-
Common stock - (15,000 )
Net cash used for financing activities (80 ) (15,080 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (49,011 ) (49,011 )
Sales of investment securities held in trusts 62,344 62,344
Purchases of investment securities held in trusts (63,797 ) (63,797 )
Loan repayments from associated companies, net 6,534 6,534
Cash investments 147 147
3,924 3,924
Net cash used for investing activities (39,859 ) (39,859 )

Net change in cash and cash equivalents $ - $ -

Currently Payable Long-term Debt
PCRBs supported by bank LOCs(1)	$	1,553
FGCO and NGC unsecured PCRBs(1)		97
CEI secured notes(2)		150
Met-Ed unsecured notes(3)		100
NGC collateralized lease obligation bonds		44
Sinking fund requirements		40
	$	1,984

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

Short-Term Borrowings

FirstEnergy had approximately $2.4 billion of short-term borrowings as of June 30, 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 July 30, 2009, FirstEnergy had $420 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 July 30, 2009, is summarized in the following table:

Company	Type	Maturity	Commitment		Available Liquidity as of July 30, 2009
			(In millions)
FirstEnergy(1)	Revolving	Aug. 2012	$	2,750	$	273
FirstEnergy and FES	Bank lines	Various(2)		120		20
FGCO	Term loan	Oct. 2009(3)		300		300
Ohio and Pennsylvania Companies	Receivables financing	Various(4)		550		451
		Subtotal	$	3,720	$	1,044
		Cash		-		921
		Total	$	3,720	$	1,965

(1) FirstEnergy Corp. and subsidiary borrowers. (2) $100 million expires March 31, 2011; $20 million uncommitted line of credit has no expiration 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 June 30, 2009:

CEI

Three Months
Ended March 31, 2008
As Previously As
Reported Restated
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 57,851 $ 57,851
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 19,076 19,076
Amortization of regulatory assets 38,256 38,256
Deferral of new regulatory assets (29,248 ) (29,248 )
Deferred rents and lease market valuation liability - -
Deferred income taxes and investment tax credits, net (4,965 ) (4,965 )
Accrued compensation and retirement benefits (3,507 ) (3,507 )
Decrease in operating assets-
Receivables 90,280 90,280
Prepayments and other current assets 604 604
Increase (decrease) in operating liabilities-
Accounts payable (28,889 ) 1,111
Accrued taxes 23,196 23,196
Accrued interest 23,831 23,831
Electric service prepayment programs (5,847 ) (5,847 )
Other (63 ) (63 )
Net cash provided from operating activities 180,575 210,575

CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt (165 ) (165 )
Short-term borrowings, net (177,960 ) (177,960 )
Dividend Payments-
Common stock - (30,000 )
Net cash used for financing activities (178,125 ) (208,125 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (37,203 ) (37,203 )
Loans to associated companies, net (2,373 ) (2,373 )
Redemptions of lessor notes 37,709 37,709
Other (574 ) (574 )
Net cash used for investing activities (2,441 ) (2,441 )

Net increase in cash and cash equivalents $ 9 $ 9

	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 June 30, 2009, FirstEnergy's and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy(1)	60.7	%
FES	53.7	%
OE	47.8	%
Penn	28.2	%
CEI	54.4	%
TE	59.7	%
JCP&L	37.2	%
Met-Ed	49.8	%
Penelec	50.9	%

(1)As of June 30, 2009, FirstEnergy could issue additional debt of approximately

$3.2 billion, or recognize a reduction in equity of approximately $1.7 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 six months of 2009 was 0.86% for the regulated companies' money pool and 1.00% for the unregulated companies' money pool.

Pollution Control Revenue Bonds

As of June 30, 2009, FirstEnergy's currently payable long-term debt included approximately $1.6 billion (FES - $1.5 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:

TE

Three Months
Ended March 31, 2008
As Previously As
Reported Restated
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 17,015 $ 17,015
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 9,025 9,025
Amortization of regulatory assets 25,025 25,025
Deferral of new regulatory assets (9,494 ) (9,494 )
Deferred rents and lease market valuation liability 6,099 6,099
Deferred income taxes and investment tax credits, net (3,404 ) (3,404 )
Accrued compensation and retirement benefits (1,813 ) (1,813 )
Decrease in operating assets-
Receivables 45,738 45,738
Prepayments and other current assets 181 181
Increase (decrease) in operating liabilities-
Accounts payable (189,243 ) (174,243 )
Accrued taxes 6,840 6,840
Accrued interest 4,663 4,663
Electric service prepayment programs (2,670 ) (2,670 )
Other 991 991
Net cash used for operating activities (91,047 ) (76,047 )

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net 52,821 52,821
Redemptions and Repayments-
Long-term debt (9 ) (9 )
Dividend Payments-
Common stock - (15,000 )
Net cash provided from financing activities 52,812 37,812

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (19,435 ) (19,435 )
Loans repayments from (loans to) associated companies, net 46,789 46,789
Redemption of lessor notes 11,989 11,989
Sales of investment securities held in trusts 3,908 3,908
Purchases of investment securities held in trusts (4,715 ) (4,715 )
Other (110 ) (110 )
Net cash provided from investing activities 38,426 38,426

Net increase in cash and cash equivalents $ 191 $ 191

	Aggregate LOC			Reimbursements of
LOC Bank	Amount(3)		LOC Termination Date	LOC Draws Due
	(In millions)
CitiBank N.A.	$	166	June 2014	June 2014
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(1)	266		June 2010	6 months
Wachovia Bank	153		March 2014	March 2014
Barclays Bank(2)	528		Beginning December 2010	30 days
PNC Bank		70	Beginning November 2010	180 days
Total	$	1,569

(1) Supported by four participating banks, with the LOC bank having 62% of the total commitment. (2) Supported by 18 participating banks, with no one bank having more than 14% of the total commitment. (3) 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. During the second quarter of 2009, NGC remarketed the remaining $334 million of PCRBs, of which $170 million was remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. During the second quarter of 2009, FGCO remarketed approximately $248 million of PCRBs supported by LOCs set to expire in June 2009. These PCRBs were remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. Also, in June 2009, FGCO and NGC delivered FMBs to certain LOC banks listed above in connection with amendments to existing letter of credit and reimbursement agreements supporting 12 other series of PCRBs as described below and pledged FMBs to the applicable trustee under six separate series of PCRBs.

Long-Term Debt Capacity

As of June 30, 2009, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.3 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMBs by 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 and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $167 million and $175 million, respectively, as of June 30, 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. As a result, the provisions for TE to incur additional secured debt do not apply.

Based upon FGCO's FMB indenture, net earnings and available bondable property additions as of June 30, 2009, FGCO had the capability to issue $2.2 billion of additional FMBs under the terms of that indenture. On June 16, 2009, FGCO issued a total of approximately $395.9 million in principal amount of FMBs, of which $247.7 million related to three new refunding series of PCRBs and approximately $148.2 million related to amendments to existing letter of credit and reimbursement agreements supporting two other series of PCRBs. On June 30, 2009, FGCO issued a total of approximately $52.1 million in principal amount of FMBs related to three existing series of PCRBs.

In June 2009, a new FMB indenture was put in place for NGC. Based upon NGC’s FMB indenture, net earnings and available bondable property additions, NGC had the capability to issue $264 million of additional FMBs as of June 30, 2009. On June 16, 2009, NGC issued a total of approximately $487.5 million in principal amount of FMBs, of which $107.5 million related to one new refunding series of PCRBs and approximately $380 million related to amendments to existing letter of credit and reimbursement agreements supporting seven other series of PCRBs. In addition, on June 16, 2009, NGC issued an FMB in a principal amount of up to $500 million in connection with its guaranty of FES’ obligations to post and maintain collateral under the Power Supply Agreement entered into by FES with the Ohio Companies as a result of the May 13-14, 2009 CBP auction. On June 30, 2009, NGC issued a total of approximately $273.3 million in principal amount of FMBs, of which approximately $92 million related to three existing series of PCRBs and approximately $181.3 million related to amendments to existing letter of credit and reimbursement agreements supporting three other series of PCRBs.

Met-Ed and Penelec had the capability to issue secured debt of approximately $428 million and $310 million, respectively, under provisions of their senior note indentures as of June 30, 2009.

FirstEnergy's access to capital markets and costs of financing are influenced by the ratings of its securities. The following table displays FirstEnergy's, FES' and the Utilities' securities ratings as of June 30, 2009. On June 17, 2009, Moody's affirmed FirstEnergy's Baa3 and FES' Baa2 credit ratings. On July 9, 2009, S&P affirmed its ratings on FirstEnergy and its subsidiaries. S&P's and Moody's outlook for FirstEnergy and its subsidiaries remains "stable."

PENELEC

Three Months
Ended March 31, 2008
As Previously As
Reported Restated
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 21,392 $ 21,392
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 12,516 12,516
Amortization of regulatory assets 16,346 16,346
Deferral of new regulatory assets (3,526 ) (3,526 )
Deferred costs recoverable as regulatory assets (8,403 ) (8,403 )
Deferred income taxes and investment tax credits, net 10,541 10,541
Accrued compensation and retirement benefits (10,488 ) (10,488 )
Cash collateral 301 301
Increase in operating assets-
Receivables (13,701 ) (13,701 )
Prepayments and other current assets (40,591 ) (40,591 )
Increase (Decrease) in operating liabilities-
Accounts payable (23,144 ) (3,144 )
Accrued taxes (5,809 ) (5,809 )
Accrued interest 510 510
Other 4,991 4,991
Net cash used for operating activities (39,065 ) (19,065 )

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net 118,209 118,209
Redemptions and Repayments
Long-term debt (45,112 ) (45,112 )
Dividend Payments-
Common stock - (20,000 )
Net cash provided from financing activities 73,097 53,097

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (28,902 ) (28,902 )
Sales of investment securities held in trusts 24,407 24,407
Purchases of investment securities held in trusts (29,083 ) (29,083 )
Loans to associated companies, net (610 ) (610 )
Other 153 153
Net cash used for investing activities (34,035 ) (34,035 )

Net decrease in cash and cash equivalents $ (3 ) $ (3 )

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

~~2. EARNINGS PER SHARE~~

~~Basic earnings per share~~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. On July 29, 2009, FES registered its common stock pursuant to Section 12(g) of the Securities Exchange Act of 1934.

Changes in Cash Position

As of June 30, 2009, FirstEnergy had $900 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 June 30, 2009, approximately $825 million of cash and cash equivalents represented temporary overnight deposits.

During the first six months of 2009, FirstEnergy received $453 million of cash from dividends and equity repurchases from its subsidiaries and paid $335 million in cash dividends to common shareholders. With the exception of Met-Ed, which is ~~computed using~~currently in an accumulated deficit position, there are no material restrictions on the ~~weighted average~~payment of ~~actual common shares outstanding during~~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 ~~respective period~~FERC to pay cash dividends from paid-in capital accounts, as long as the ~~denominator. The denominator for diluted earnings per share~~subsidiary’s debt to total capitalization ratio (without consideration of ~~common stock reflects~~retained earnings) remains below 65%. CEI and TE are the ~~weighted average~~only utility subsidiaries currently precluded from that action.

Cash Flows From Operating Activities

FirstEnergy's consolidated net cash from operating activities is provided primarily by its competitive energy services and energy delivery services businesses (see Results of ~~common shares outstanding plus~~Operations above). Net cash provided from operating activities was $1.1 billion and $319 million in the ~~potential additional common shares that could result if dilutive securities~~first six months of 2009 and 2008, respectively, as summarized in the following table:

	Six Months
	Ended June 30
Operating Cash Flows	2009			2008
	(In millions)
Net income	$	523		$	540
Non-cash charges		719			435
Working capital and other		(140	)		(656	)
	$	1,102		$	319

Net cash provided from operating activities increased by $783 million in the first six months of 2009 compared to the first six months of 2008 primarily due to a $284 million increase in non-cash charges and a $516 million increase from working capital and other ~~agreements~~changes, partially offset by a $17 million decrease in net income (see Results of Operations above). The increase in non-cash charges is primarily due to ~~issue common stock were exercised.~~higher net amortization of regulatory assets, including CEI’s $216 million regulatory asset impairment, and changes in accrued compensation and retirement benefits. The ~~pool~~change in accrued compensation and retirement benefits resulted from higher non-cash retirement benefit expenses recognized in the first six months of 2009. The changes in working capital and other primarily resulted from lower net tax payments of $278 million, a $70 million decrease in stock-based compensation ~~tax benefits is calculated~~payments and an increase in ~~accordance~~other accrued expenses principally associated with ~~SFAS 123(R). On March 2, 2007, FirstEnergy repurchased approximately 14.4~~the implementation of the Ohio Companies’ Amended ESP.

Cash Flows From Financing Activities

In the first six months of 2009, cash provided from financing activities was $426 million ~~shares, or 4.5%,~~compared to $1.2 billion in the first six months of ~~its outstanding common stock through an accelerated share repurchase program at an initial price~~2008. The decrease was primarily due to reduced short-term borrowings, partially offset by long-term debt issuances in the first six months of ~~approximately $900 million. A final purchase price adjustment of $51 million was settled in cash on December 13, 2007.~~2009. The following table ~~reconciles basic~~summarizes security issuances (net of any discounts) and ~~diluted earnings per share of common stock:~~redemptions.

Reconciliation of Basic and Diluted
Three Months Ended
March 31,

Earnings per Share of Common Stock 2008 2007

(In millions, except
per share amounts)
Net income $ 276 $ 290

Average shares of common stock outstanding – Basic 304 314
Assumed exercise of dilutive stock options and awards 3 2
Average shares of common stock outstanding – Dilutive 307 316

Basic earnings per share of common stock $ 0.91 $ 0.92
Diluted earnings per share of common stock $ 0.90 $ 0.92

~~3. DIVESTITURES AND DISCONTINUED OPERATIONS~~

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 March 31, 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 March 31, 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.

	Six Months
	Ended June 30
Securities Issued or Redeemed	2009		2008
	(In millions)
New issues
First mortgage bonds	$	100	$	-
Pollution control notes		682		529
Senior secured notes		297		-
Unsecured notes		600		20
	$	1,679	$	549

Redemptions
First mortgage bonds	$	-	$	1
Pollution control notes		682		529
Senior secured notes		46		15
Unsecured notes		153		175
	$	881	$	720

Short-term borrowings, net	$	-	$	1,705

The following table ~~sets forth FirstEnergy’s financial assets~~summarizes new debt issuances (excluding PCRB issuances and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of March 31, 2008. As required by SFAS 157, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

March 31, 2008
Recurring Fair Value Measures Level 1 Level 2 Level 3 Total
(In millions)
Assets:
    Derivatives $ 4 $ 98 $ - $ 102
    Nuclear decommissioning trusts(1)
1,070 953 - 2,023
    Other investments(2)
21 303 - 324
    Total $ 1,095 $ 1,354 $ - $ 2,449

Liabilities:
    Derivatives $ - $ 98 $ - $ 98
    NUG contracts(3)
- - 682 682
    Total $ - $ 98 $ 682 $ 780
refinancings) during 2009.

~~(1)~~

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

~~(2)~~

~~Excludes $318 million of the cash surrender value of life insurance contracts.~~

~~(3)~~

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

Issuing Company	Issue Date	Principal (in millions)	Type	Maturity	Use of Proceeds

Met-Ed*	01/20/2009	$300	7.70% Senior Notes	2019	Repay short-term borrowings

JCP&L*	01/27/2009	$300	7.35% Senior Notes	2019	Repay short-term borrowings, fund capital expenditures and other general purposes

TE*	04/24/2009	$300	7.25% Senior Secured Notes	2020	Repay short-term borrowings, fund capital expenditures and other general purposes

Penn	06/30/2009	$100	6.09% FMB	2022	Fund capital expenditures and repurchase equity from OE

* Issuance was sold off the shelf registration statement referenced above.

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.Cash Flows From Investing Activities

~~Exchange-traded derivative contracts, which include some futures~~Net cash flows used in investing activities resulted primarily from property additions. Additions for the energy delivery services segment primarily represent expenditures related to transmission 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 corroborateddistribution facilities. Capital spending by the ~~market. When such inputs have a significant impact on~~competitive energy services segment is principally generation-related. The following table summarizes investing activities for the ~~measurement of fair value, the instrument is classified as Level 3.~~six months ended June 30, 2009 and 2008 by business segment:

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.

Summary of Cash Flows	Property
Provided from (Used for) Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Six Months Ended June 30, 2009
Energy delivery services	$	(343	)	$	48		$	(23	)	$	(318	)
Competitive energy services		(669	)		2			(22	)		(689	)
Other		(119	)		(7	)		(3	)		(129	)
Inter-Segment reconciling items		(12	)		(25	)		-			(37	)
Total	$	(1,143	)	$	18		$	(48	)	$	(1,173	)

Six Months Ended June 30, 2008
Energy delivery services	$	(451	)	$	44		$	(4	)	$	(411	)
Competitive energy services		(1,145	)		(9	)		(62	)		(1,216	)
Other		(21	)		49			6			34
Inter-Segment reconciling items		-			(12	)		-			(12	)
Total	$	(1,617	)	$	72		$	(60	)	$	(1,605	)

~~The following table sets forth a reconciliation of changes~~

Net cash used for investing activities in the ~~fair~~first six months of 2009 decreased by $432 million compared to the first six months of 2008. The decrease was principally due to a $474 million decrease in property additions, which reflects lower AQC system expenditures and the absence in 2009 of the purchase of certain lessor equity interests in Beaver Valley Unit 2 and Perry, and the purchase of a partially-completed generating plant in Fremont, Ohio. The decrease in property additions was partially offset by the absence in 2009 of cash proceeds from the sale of telecommunication assets in the first quarter of 2008.

During the second half of 2009, capital requirements for property additions and capital leases are expected to be approximately $773 million, including approximately $176 million for nuclear fuel. FirstEnergy has additional requirements of approximately $177 million for maturing long-term debt during the remainder of 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 $7.9 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 $337 million applies to 2009. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $1.0 billion and $131 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 June 30, 2009, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.6 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)	$	427
LOC (long-term debt) – interest coverage (2)		6
FirstEnergy guarantee of OVEC obligations		300
Other (3)		600
		1,333

Subsidiaries’ Guarantees
Energy and Energy-Related Contracts		54
LOC (long-term debt) – interest coverage (2)		6
FES’ guarantee of NGC’s nuclear property insurance		77
FES’ guarantee of FGCO’s sale and leaseback obligations		2,502
		2,639

Surety Bonds		108
LOC (long-term debt) – interest coverage (2)		4
LOC (non-debt) (4)(5)		501
		613
Total Guarantees and Other Assurances	$	4,585

(1)

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

(2)

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

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 $80 million for nuclear decommissioning funding (see

Nuclear Plant Matters below) assurances and $161 million supporting OE’s sale

and leaseback arrangement. Also includes $300 million for a Credit Suisse credit

facility for FGCO that is guaranteed by both FirstEnergy and FES.

(4)

Includes $161 million issued for various terms pursuant to LOC capacity available

under FirstEnergy’s revolving credit facility.

(5)

Includes approximately $206 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 by OE.

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 June 30, 2009, FirstEnergy’s maximum exposure under these collateral provisions was $601 million as shown below:

Collateral Provisions	FES		Utilities		Total
	(In millions)
Credit rating downgrade to below investment grade	$	315	$	110	$	425
Acceleration of payment or funding obligation		80		55		135
Material adverse event		41		-		41
Total	$	436	$	165	$	601

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 $700 million, consisting of $49 million due to “material adverse event” contractual clauses and $651 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 June 30, 2009, and forward prices as of that date, FES had $179 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 $73 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post significantly higher amounts for margining.

In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in the amount of approximately $500 million, dated as of June 16, 2009, in favor of the Ohio Companies.

FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, pursuant to guarantees entered into on March 26, 2007. Similar guarantees were entered into on that date pursuant to which FES guaranteed the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC will have claims against each of FES, FGCO and NGC regardless of whether their primary obligor is FES, FGCO or NGC.

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 ~~NUG contracts classified~~these sale and leaseback operating lease commitments, net of trust investments is $1.7 billion as ~~Level 3 in the fair value hierarchy for the three months ended March 31, 2008 (in millions):~~of June 30, 2009.

Balance as of January 1, 2008 $ 750
    Realized and unrealized gains (losses)(1)
(58 )
    Purchases, sales, issuances and settlements, net(1)
(10 )
    Net transfers to (from) Level 3 -
Balance as of March 31, 2008 $ 682

Change in unrealized gains (losses) relating to
    instruments held as of March 31, 2008 $ (58 )

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

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

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~~MARKET RISK INFORMATION

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

Commodity Price Risk

FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices ~~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 that do not meet the normal purchases and normal sales criteria are recorded as other expense, as AOCL, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness. FirstEnergy does not offset fair value for the right to reclaim collateral or the obligation to return collateral.

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

The net deferred losses of $84 million included in AOCL as of March 31, 2008, for derivative hedging activity, as compared to $75 million as of December 31, 2007, resulted from a net $21 million increasecontracts related to ~~current hedging activity and a $12 million decrease due to net hedge losses reclassified to earnings~~energy production during the three months and six months ended ~~March 31, 2008.~~June 30, 2009 are summarized in the following table:

	Three Months									Six Months
	Ended June 30, 2009									Ended June 30, 2009
Fair Value of Commodity Derivative Contracts	Non-Hedge			Hedge			Total			Non-Hedge			Hedge			Total
	(In millions)
Change in the Fair Value of
Commodity Derivative Contracts:
Outstanding net liability at beginning of period	$	(457	)	$	(29	)	$	(486	)	$	(304	)	$	(41	)	$	(345	)
Additions/change in value of existing contracts		(154	)		8			(146	)		(381	)		(2	)		(383	)
Settled contracts		96			7			103			170			29			199
Outstanding net liability at end of period (1)	$	(515	)	$	(14	)	$	(529	)	$	(515	)	$	(14	)	$	(529	)

Non-commodity Net Liabilities at End of Period:
Interest rate swaps (2)		-			(3	)		(3	)		-			(3	)		(3	)
Net Liabilities - Derivative Contracts at End of Period	$	(515	)	$	(17	)	$	(532	)	$	(515	)	$	(17	)	$	(532	)

Impact of Changes in Commodity Derivative Contracts(3)
Income statement effects (pre-tax)	$	2		$	-		$	2		$	3		$	-		$	3
Balance sheet effects:
Other comprehensive income (pre-tax)	$	-		$	15		$	15		$	-		$	27		$	27
Regulatory assets (net)	$	60		$	-		$	60		$	214		$	-		$	214

(1)	Includes $517 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 June 30, 2009 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	2		$	21		$	23
Other liabilities		-			(31	)		(31	)

Non-Current-
Other deferred charges		233			-			233
Other non-current liabilities		(750	)		(7	)		(757	)
Net liabilities	$	(515	)	$	(17	)	$	(532	)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 4 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of June 30, 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)	$	(7	)	$	(11	)	$	-		$	-		$	-		$	-	$	(18	)
Other external sources(3)		(147	)		(252	)		(204	)		(120	)		-			-		(723	)
Prices based on models		-			-			-			-			(1	)		213		212
Total(4)	$	(154	)	$	(263	)	$	(204	)	$	(120	)	$	(1	)	$	213	$	(529	)

(1) For the last two quarters of 2009.

(2) Represents exchange traded NYMEX futures and options.

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

(4)

Includes $517 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of June 30, 2009. Based on ~~current estimates, approximately $19 million (after tax) of the net deferred losses on~~ derivative ~~instruments in AOCL~~contracts held as of ~~March 31, 2008 are expected to be reclassified to earnings~~June 30, 2009, an adverse 10% change in commodity prices would decrease net income by approximately $4 million 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 March 31, 2008, FirstEnergy had interest rate swaps with an aggregate notional value of $250 million and a fair value of $5 million.

Agreements - Cash Flow Hedges

~~During 2007 and the first three 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 ~~three~~six months of ~~2008,~~2009, FirstEnergy terminated forward swaps with aan aggregate notional value of ~~$300 million and entered into swaps with a notional value of $500~~$100 million. FirstEnergy paid ~~$18~~$1.3 million in cash related to the terminations, $1$0.3 million of which was deemed ineffective and recognized in current period earnings. ~~FirstEnergy~~The remaining effective portion ($1 million) will ~~recognize the remaining $17 million loss~~be recognized over the ~~life~~terms of the associated future debt. As of ~~March 31, 2008,~~June 30, 2009, FirstEnergy had outstanding forward swaps with an aggregate notional amount of ~~$600~~$200 million and aan aggregate fair value of ~~$(8)~~$(3) million.

~~6. ASSET RETIREMENT OBLIGATIONS~~

	June 30, 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	$	(1	)	$	100		2009	$	(2	)
		100		2010		(2	)		100		2010		(2	)
		-		2019		-			100		2019		1
	$	200			$	(3	)	$	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 liability of $1.3 billion as of March 31, 2008 is primarily related to the future nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of March 31, 2008, the fair value of the decommissioning trust assets was approximately $2.0 billion.

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

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

(In millions)

Balance, January 1, 2008

$
1,267

$
810

$
94

$
2

$
28

$
90

$
161

$
82

Liabilities incurred

-

-

-

-

-

-

-

-

Liabilities settled

-

-

-

-

-

-

-

-

Accretion

20

14

1

-

1

1

2

1

Revisions in estimated cash flows
-
-

-

-

-

-

-

-

Balance, March 31, 2008
$ 1,287
$
824

$
95

$
2

$
29

$
91

$
163

$
83

Balance, January 1, 2007

$
1,190

$
760

$
88

$
2

$
27

$
84

$
151

$
77

Liabilities incurred

-

-

-

-

-

-

-

-

Liabilities settled

-

-

-

-

-

-

-

-

Accretion

18

12

1

-

-

2

2

1

Revisions in estimated cash flows

-

-

-

-

-

-

-

-

Balance, March 31, 2007

$
1,208

$
772

$
89

$
2

$
27

$
86

$
153

$
78

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

FirstEnergy provides a noncontributory qualified defined benefit pension ~~plans~~plan that ~~cover~~covers substantially all of its employees and ~~those of its subsidiaries.~~non-qualified pension plans that cover 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. ~~FirstEnergy recognizes the expected cost of providing pension benefits~~The benefit plan assets and obligations are remeasured annually using a December 31 measurement date. FirstEnergy’s other postretirement benefits ~~from the time employees are hired until they become eligible to receive those benefits. In addition,~~plans were remeasured as of May 31, 2009 as a result of a plan amendment announced on June 2, 2009, which reduces future health care coverage subsidies paid by FirstEnergy ~~has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.~~

on behalf of plan participants. The ~~components of FirstEnergy's~~remeasurement and plan amendment will result in a $48 million reduction in FirstEnergy’s net ~~periodic pension cost and other~~ postretirement benefit cost (including amounts capitalized) for the ~~three months ended March~~remainder of 2009, including a $7 million reduction that is applicable to the second quarter of 2009 (see Note 5). 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 ~~2007, consisted~~FirstEnergy currently estimates that additional cash contributions will be required in 2011 for the 2010 plan year. The overall actual investment result during 2008 was a loss of ~~the following:~~

Pension Benefits Other Postretirement Benefits
2008 2007 2008 2007
(In millions)
Service cost

$
21

$
21

$
5

$
5

Interest cost

72

71

18

17

Expected return on plan assets

(115
)

(112
)

(13
)

(13
)
Amortization of prior service cost

2

2

(37
)

(37
)
Recognized net actuarial loss

1

10

12

12

Net periodic cost (credit)

$
(19
)
$
(8)

$
(15
)
$
(16
)

~~Pension and postretirement benefit obligations are allocated~~23.8% compared to ~~FirstEnergy’s subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The~~an assumed 9% positive return. Based on assumed 7-7.5% discount rates, FirstEnergy's pre-tax net periodic pension ~~costs~~ and ~~net periodic postretirement benefit costs (including amounts capitalized) recognized by each of the Companies for the three months ended March 31, 2008 and 2007 were as follows:~~

Pension Benefit Cost (Credit)
Other Postretirement
Benefit Cost (Credit)

2008 2007 2008 2007
(In millions)
FES

$
4

$
-

$
(2
)
$
-

OE

(7
)
(4
)
(2
)
(3
)
CEI

(1
)
-

1

1

TE

(1
)
-

1

1

JCP&L

(4
)

(2
)

(4
)
(4
)
Met-Ed

(3
)

(2
)

(3
)
(2
)
Penelec

(3
)

(3
)

(3
)
(3
)
Other FirstEnergy
subsidiaries

(4
)

3

(3
)
(6
)

$
(19
)
$
(8
)
$
(15
)
$
(16
)

~~8. VARIABLE INTEREST ENTITIES~~

FIN 46R addresses the 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~~OPEB expense was established to purchase a portion of the lease obligation bonds issued in connection with OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.

~~Loss Contingencies~~

FES and the Ohio Companies are exposed to losses under their applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments are made. The following table shows each company’s net exposure to loss based upon the casualty value provisions mentioned above as of March 31, 2008:

Maximum Exposure
Discounted
Lease
Payments, net

Net
Exposure
(in millions)
FES $ 1,364 $ 1,216 $ 148
OE 819 628 191
CEI 782 77 705
TE 782 457 325

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

On March 3, 2008, notice was given to the nine owner trusts that are lessors under sale and leaseback transactions, originally entered into by TE in 1987, that NGC would acquire the related 18.26% undivided interest in Beaver Valley Unit 2 through the exercise of the periodic purchase option provided for in the applicable facility leases. The purchase price to be paid by NGC for the undivided interest will be equal to the higher of a specified casualty value under the applicable facility leases (approximately $239$38 million in the ~~aggregate for the equity portion~~second quarter of all nine facility leases) and the fair market sales value of such undivided interests. Determination of the fair market sales value may become subject to an appraisal procedure provided for in the lease documentation. An additional payment of approximately $236 million would be required to prepay in full the outstanding principal of, and accrued but unpaid interest on, the lessor notes of the nine owner trusts. Alternatively, this amount would not be paid as part of the aggregate purchase price if the lessor notes are instead assumed at the time of the exercise of the option. If NGC determines to prepay the notes, it is possible that the proceeds from such prepayment may not be sufficient to pay the principal of, and interest on, the bonds as they become due. If that is the case, NGC would provide a mechanism to address any such potential shortfall in a timely manner.2009.

~~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 to be recovered from customers. Purchased power costs from these entities during the three months ended March 31, 2008 and 2007 are shown in the following table:

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

$
19

$
20

Met-Ed

16

15

Penelec

8

8

$
43

$
43

Nuclear decommissioning trust funds have been established to satisfy NGC's and the Utilities' nuclear decommissioning obligations. As of June 30, 2009, approximately 34% of the funds were invested in equity securities and 66% were invested in fixed income securities, with limitations related to concentration and investment grade ratings. The equity securities are carried at their market value of approximately $588 million as of June 30, 2009. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $59 million reduction in fair value as of June 30, 2009. The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts based on the guidance for other-than-temporary impairments provided in SFAS 115, FSP SFAS 115-1 and SFAS 124-1. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. Renewal of the operating license for Beaver Valley Unit 1 (see Nuclear Plant Matters) would mitigate the estimated shortfall in the unit’s nuclear decommissioning funding status. FENOC continues to communicate with the NRC regarding future actions to provide reasonable assurance for decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.

CREDIT RISK

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

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of June 30, 2009, the largest credit concentration was with JP Morgan, which is currently rated investment grade, representing 9.4% of FirstEnergy's total approved credit risk.

OUTLOOK

~~Transition Bonds~~State Regulatory Matters

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 ~~consolidated financial statements~~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 ~~FirstEnergy~~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 $158 million as of June 30, 2009 (JCP&L - $48 million, Met-Ed - $95 million and ~~JCP&L include the results of JCP&L Transition Funding~~Penelec - $15 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs 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~~employee postretirement benefits) are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of March 31, 2008, $391 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.

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~~recovered by 2014 for JCP&L and ~~transition.~~by 2020 for Met-Ed and Penelec. The ~~evaluation of a tax position in accordance with this interpretation is a two-step process.~~following table discloses net regulatory assets by company:

	June 30,		December 31,		Increase
Regulatory Assets	2009		2008		(Decrease)
	(In millions)
OE	$	514	$	575	$	(61	)
CEI		628		784		(156	)
TE		91		109		(18	)
JCP&L		1,055		1,228		(173	)
Met-Ed		497		413		84
Penelec*		10		-		10
ATSI		24		31		(7	)
Total	$	2,819	$	3,140	$	(321	)

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

Regulatory assets by source are as follows:

	June 30,			December 31,			Increase
Regulatory Assets By Source	2009			2008			(Decrease)
	(In millions)
Regulatory transition costs	$	1,278		$	1,452		$	(174	)
Customer shopping incentives		218			420			(202	)
Customer receivables for future income taxes		332			245			87
Loss on reacquired debt		52			51			1
Employee postretirement benefits		27			31			(4	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(115	)		(57	)		(58	)
Asset removal costs		(226	)		(215	)		(11	)
MISO/PJM transmission costs		279			389			(110	)
Purchased power costs		360			214			146
Distribution costs		482			475			7
Other		132			135			(3	)
Total	$	2,819		$	3,140		$	(321	)

Reliability Initiatives

In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The ~~first step is~~mandatory reliability standards apply to ~~determine if it is more likely than not that a tax position will be sustained upon examination, based~~the bulk power system and impose certain operating, record-keeping and reporting requirements on the ~~merits~~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 position, and should therefore be recognized. The second step is to measure a tax position that meets the more likely than not recognition threshold to determine the amount of income tax benefit to recognize in the financial statements.reliability standards.

~~As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits was $268 million.~~ FirstEnergy recorded a $2.7 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate upon recognition. The majority of items that would not have affected the effective tax rate would be purchase accounting adjustments to goodwill upon recognition. During the first three months of 2008 and 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of March 31, 2008, FirstEnergy expectsbelieves that it is ~~reasonably possible~~in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that ~~$8 million~~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 ~~unrecognized benefits will~~2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be ~~resolved within~~recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the ~~next twelve months and is included~~reliability standards for its bulk power system could result in the ~~caption “accrued taxes,” with the remaining $263 million included in the caption “other non-current liabilities” on the Consolidated Balance Sheets.~~

FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48imposition of financial penalties and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. The net amount of interest accrued as of March 31, 2008 was $57 million, as compared to $53 million as of December 31, 2007. During the first three months of 2008 and 2007, there were no material changes to the amount of interest accrued.

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

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.

2930

~~10. COMMITMENTS, GUARANTEES AND CONTINGENCIES~~

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 the NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviews with personnel involved in responding to the event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L is required to reply by August 7, 2009. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittal or interview results.

~~(A) GUARANTEES AND OTHER ASSURANCES~~On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. ReliabilityFirst issued an Initial Notice of Alleged Violation on June 22, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-report of violation.

AsOhio

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. On January 21, 2009, the PUCO granted the Ohio Companies’ application to increase electric distribution 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 for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.

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, which is still pending. 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 provided generation service to the Ohio Companies’ retail customers who chose 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 denied OE’s and TE’s request to continue collecting RTC and denied the request to allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider recovered the increased purchased power costs for OE and TE, and recovered a portion of those costs for CEI, with the remainder being deferred 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 provided that generation would 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 would be based upon the outcome of a descending clock CBP on a slice-of-system basis. The Amended ESP further provided 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 would agree to write-off approximately $216 million of its Extended RTC balance, and that the Ohio Companies would 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 addressed a number of other issues, including but not limited to, rate design for various customer classes, and 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, 2009 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 took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009.

On July 27, 2009, the Ohio Companies filed applications with the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a 5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for these deferrals is a total of $298.4 million. If the applications are approved, recovery of this amount, together with carrying charges calculated as approved in the Amended ESP, will be collected in the 18 non-summer months from September 2009 through May 2011, subject to reconciliation until fully collected, with $165 million of the above amount being recovered from residential customers, and $133.4 million being recovered from non-residential customers. Pursuant to the applications, customers would pay significantly less over the life of the recovery of the deferral through the reduction in carrying charges as compared to the expected recovery under the previously approved recovery mechanism.

The Ohio Companies are presently involved in collaborative efforts related to energy efficiency and a competitive bidding process, together with other implementation efforts arising out of the Supplemental Stipulation. The CBP auction occurred on May 13-14, 2009, and resulted in a weighted average wholesale price for generation and transmission of 6.15 cents per KWH. The bid was for a single, two-year product for the service period from June 1, 2009 through May 31, 2011. FES participated in the auction, winning 51% of the tranches (one tranche equals one percent of the load supply). Subsequent to the signing of the wholesale contracts, two winning bidders reached separate agreements with FES to assign a total of 11 tranches to FES for various periods. In addition, FES has separately contracted with numerous communities to provide retail generation service through governmental aggregation programs.

SB221 also requires electric distribution utilities to implement energy efficiency programs that achieve a total annual 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 1%, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. Additionally, electric utilities and electric service companies are required to serve part of ~~normal business activities,~~their load from renewable energy resources equivalent to 0.25% of the KWH they serve in 2009. FirstEnergy ~~enters~~has efforts underway to address compliance with these requirements. Costs associated with compliance are recoverable from customers.

On June 17, 2009, the PUCO modified rules that implement the alternative energy portfolio standards created by SB221, including the incorporation of energy efficiency requirements, long-term forecast and greenhouse gas reporting and CO2 control planning. The PUCO filed the rules with the Joint Committee on Agency Rule Review on July 7, 2009, after which begins a 65-day review period. The Ohio Companies and one other party filed applications for rehearing on the rules with the PUCO on July 17, 2009.

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. 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 included a component from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and 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 May 28, 2009, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider 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 resulted 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 increased 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, the PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs to a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers will 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. Act 129 addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. 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 prudent 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;

·	utilities must reduce peak demand by a minimum of 4.5% by May 31, 2013;

·	utilities must reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and

·	the definition of Alternative Energy was expanded to include additional types of hydroelectric and biomass facilities.

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. On June 18, 2009, the PPUC issued its guidelines related to Smart Meter deployment. On July 1, 2009, Met-Ed, Penelec, and Penn filed Energy Efficiency and Conservation Plans with the PPUC in accordance with Act 129.

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 February 26, 2009, the PPUC approved a Voluntary Prepayment Plan 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 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. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the companies’ Restructuring Orders of 1998. Met-Ed and Penelec are awaiting PPUC action on the July 31, 2009 filings.

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, 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, 2009, the accumulated deferred cost balance totaled approximately $149 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, FirstEnergy cannot determine the impact, if any, 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 a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. Approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million would be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent on energy efficiency programs that would complement those currently being offered. Implementation of the projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal.

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

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 ~~agreements~~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. AEP's 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 arguments were held on April 13, 2009. A decision is expected this summer.

The FERC’s orders on PJM rate design would 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 would 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

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 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 was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its ~~subsidiaries~~affiliated operating utility companies, filed a motion to intervene on March 10, 2009.

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. 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 discussions. 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 March 26, 2009 Order; and subsequently, numerous parties filed requests for rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied rehearing and request for oral argument of the March 26 Order.

PJM has reconvened the Capacity Market Evolution Committee to address issues not addressed in the February 2009 settlement in preparation for September 1, 2009 and December 1, 2009 compliance filings that will recommend more incremental improvements to its RPM.

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 and FES. This requirement was 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 was implemented as planned on June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify.

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 ~~financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As~~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 a December 23, 2008 ~~outstanding guarantees and other assurances aggregated approximately $4.4 billion, consisting~~waiver of ~~parental guarantees - $0.9 billion, subsidiaries’ guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $0.7 billion.~~restrictions on affiliate sales without prior approval of the FERC.

~~FirstEnergy guarantees~~On May 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate in the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES was the successful bidder for 51 tranches, and subsequently purchased 11 additional tranches from other bidders. The auction resulted in an overall weighted average wholesale price of 6.15 cents per KWH for generation and transmission. The new prices for PLR service went into effect with usage beginning June 1, 2009, and continuing through May 31, 2011.

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 ~~energy-related payments~~2010 to approximately two-thirds of ~~its subsidiaries involved~~those affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit supportplace for the ~~financing~~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 ~~refinancing~~failure of supply of their committed resources. Prices for the power provided 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 counterpartyFES 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 (includednot changed in the $0.9 billion discussed above) as of March 31, 2008 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.Third Restated Partial Requirements Agreement.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $66 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $2 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($19 million as of March 31, 2008), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

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~~

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~~$808 million for the period ~~2008-2012.~~2009-2013.

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

Clean Air Act Compliance

FirstEnergy is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to ~~$32,500~~$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.

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

FirstEnergy complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achieved through combustion controls, ~~and~~ the generation of more electricity at lower-emitting ~~plants.~~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 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, under a Cooperative Agreement with the Agency for Toxic Substances and Disease Registry, completed a Health Consultation regarding the Mansfield Plant and issued a report dated March 31, 2009 which concluded there is insufficient sampling data to determine if any public health threat exists for area residents due to emissions from the Mansfield Plant. The report recommended additional air monitoring and sample analysis in the vicinity of the Mansfield Plant which the Pennsylvania Department of Environmental Protection is currently conducting.

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. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey ~~alleges~~allege that "modifications" at Portland Units 1 and 2 occurred between 1980 and ~~1995~~2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and ~~seeks~~seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On ~~March 14,~~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 and Connecticut’s 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 1, 2009, the Court held oral argument on Met-Ed’s motion to dismiss the ~~citizen suit claims against it~~complaint.

On June 11, 2008, the EPA issued a Notice and ~~a stipulation in which~~Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications" at the ~~parties agreed that GPU, Inc. should be dismissed~~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 ~~this case. On March 26, 2008, GPU, Inc. was dismissed by~~Penelec, the ~~Court. Although it remains liable for civil or criminal penalties~~co-owner (along with New York State Electric and ~~fines that may be assessed relating to events~~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 ~~sale~~outcome of this matter.

On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the ~~Portland Station in 1999, Met-Ed is indemnified by Sithe Energy against any other liability arising under~~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 ~~it arises out~~these generating sources are complying with the NSR provisions of ~~pre-1999 or post-1999 events.~~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)~~. FirstEnergy's Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO~~2 ~~and NO~~X ~~emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on NO~~X ~~emissions. According to the EPA, SO~~2 ~~emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015,~~, ultimately capping SO2 emissions in affected states to ~~just~~ 2.5 million tons ~~annually.~~annually and NOX emissions ~~will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO~~X ~~cap of~~to 1.3 million tons annually. CAIR ~~has been~~was challenged in the United States Court of Appeals for the District of ~~Columbia. The~~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. On July 10, 2009, the United States Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the "8-hour" ozone NAAQS. FGCO's future cost of compliance with these regulations may be substantial and ~~may~~will depend, in part, on the ~~outcome of this litigation and how CAIR is ultimately implemented.~~action taken by the EPA in response to the Court’s ruling.

Mercury Emissions

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

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

~~W. H. Sammis Plant~~

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

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

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing, by 2012, the amount of man-made GHG, including CO2, emitted by developed ~~countries by 2012.~~countries. The United States signed the Kyoto Protocol in 1998 but it ~~failed to receive the two-thirds vote required~~was never submitted for ratification by the United States Senate. However, the Bush administration has 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, theThe 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 used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the ~~Senate Environmental and Public Works Committees have~~House of Representatives passed one such ~~bill.~~bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. 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.

3240

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 ~~(BPJ)~~ to minimize impacts on fish and shellfish from cooling water intake structures. On April ~~14, 2008,~~1, 2009, the Supreme Court of the United States ~~granted a petition for a writ of certiorari to review certain aspects~~reversed one significant aspect of the Second ~~Circuit’s decision.~~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 ~~the outcome of the Supreme Court’s review of the Second Circuit’s decision,~~and the EPA’s further rulemaking and any action taken by the states exercising ~~BPJ,~~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 ~~Hazardous~~ 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. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion wastes. FGCO's future cost of compliance with any coal combustion waste regulations which may be promulgated could be substantial and would 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, 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~~Utilities have been named as ~~PRPs~~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 ~~PRPs~~potentially responsible parties for a particular site may be liable on a joint and several basis. ~~Therefore, environmental~~Environmental liabilities that are considered probable have been recognized on the ~~Consolidated Balance Sheet~~consolidated balance sheet as of ~~March 31, 2008,~~June 30, 2009, based on estimates of the total costs of cleanup, the ~~Companies'~~Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately ~~$92~~$104 million ~~(JCP&L - $65 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million)~~ have been accrued through ~~March 31, 2008.~~June 30, 2009. Included in the total ~~for JCP&L~~ are accrued liabilities of approximately ~~$56~~$68 million for environmental remediation of former manufactured gas plants and gas holder facilities in New ~~Jersey;~~Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

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

Power Outages and Related Litigation

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

~~In August 2002,~~After various motions, rulings and appeals, the ~~trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs'~~Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, ~~and~~ strict product ~~liability. In November 2003,~~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, ~~granted JCP&L's motion to decertify~~and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited 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 limitedonly 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~~which resulted 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~~period, 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,(2) in March 2007, ~~reversed~~ the ~~decertification of the Red Bank class and~~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. On March 31, 2009, the trial court again granted JCP&L&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed a ~~petition~~motion for ~~allowance of~~leave to take an interlocutory appeal ofto the trial court's decision to decertify the class, which was granted by the Appellate Division ~~ruling~~on June 15, 2009. According to the ~~New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in~~scheduling order issued by the ~~Superior Court~~Appellate Division, Plaintiffs' opening brief is due on August 25, 2009, JCP&L's opposition brief is due on September 25, 2009, and ~~a case management conference with the presiding Judge~~Plaintiffs' reply is ~~scheduled for June 13, 2008. FirstEnergy is defending this class action but is unable to predict the outcome of this matter. No liability has been accrued as of March 31, 2008.~~due on October 5, 2009.

Nuclear Plant Matters

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 ~~May 14, 2007, the Office of Enforcement of~~June 8, 2009, the NRC issued the final Safety Evaluation Report (SER) supporting the renewed license for Beaver Valley Units 1 and 2. On July 8, 2009, the NRC’s Advisory Committee on Reactor Safeguards (ACRS) held a ~~DFI~~public meeting to consider the NRC’s final SER. Much of the ACRS’ discussion involved questions raised by a letter from Citizens Power regarding the extent of corrective actions for the 2009 discovery of a penetration in the Beaver Valley Unit 1 containment liner. On July 28, 2009, FENOC ~~following FENOC’s reply~~submitted to the NRC further clarifications on the supplemental volumetric examinations of Beaver Valley’s containment liners. FENOC anticipates another meeting with the ACRS regarding the container liner during September 2009. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and is scheduled 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.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2009, FirstEnergy had approximately $1.7 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 provided an ~~April 2, 2007 NRC request~~additional $80 million parental guarantee associated with the funding of decommissioning costs 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 NRCthese units and indicated that ~~this information was needed for~~it planned to contribute an additional $80 million to these trusts by 2010. As required by the NRC, ~~“to determine whether an Order~~FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligations to fund the trusts may increase. The recent disruption in the capital markets and its effects on particular businesses and the economy in general also affects the values of the nuclear decommission trusts. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. On July 28, 2009, FENOC submitted a letter to the NRC that stated reasonable assurance of decommissioning funding is provided for Beaver Valley Unit 1 through a combination of the existing trust fund balances, the existing $80 million parental guarantee from FirstEnergy and maintaining the plant in a safe-store configuration, or ~~other action should be taken pursuant~~extended safe shutdown condition, after plant shutdown. Renewal of the operating license for Beaver Valley Unit 1, as described above, would mitigate the estimated shortfall in the unit’s nuclear decommissioning funding status. FENOC continues to ~~10 CFR 2.202,~~communicate with the NRC regarding future actions to provide reasonable assurance ~~that FENOC will continue~~for decommissioning funding. Such actions may include additional parental guarantees or contributions to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC’s compliance with these commitments is subject to future NRC review.those funds.

Other Legal Matters

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

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

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. ~~At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings.~~ On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. ~~On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005.~~ A final order identifying the individual damage amounts was issued on October 31, ~~2007. The~~2007 and the award appeal process was initiated. The union filed a motion with the federal ~~court~~Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. 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 ~~court held a scheduling conference in April 2008 where it set a briefing schedule with all briefs to be concluded by July 2008.~~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~~bargaining unit employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. ~~The parties are~~On July 24, 2009, FirstEnergy declared that bargaining was at an impasse and portions of its last contract offer were implemented August 1, 2009. A federal mediator is continuing to ~~bargain with~~assist the ~~assistance of~~parties in reaching a ~~federal mediator.~~ negotiated contract settlement. FirstEnergy has a strike mitigation plan ready in the event of a strike.

On May 21, 2009, 517 Penelec employees, represented by the International Brotherhood of Electrical Workers (IBEW) Local 459, elected to strike. In response, on May 22, 2009, Penelec implemented its work-continuation plan to use nearly 400 non-represented employees with previous line experience and training drawn from Penelec and other FirstEnergy operations to perform service reliability and priority maintenance work in Penelec’s service territory. Penelec's IBEW Local 459 employees ratified a three-year contract agreement on July 19, 2009, and returned to work on July 20, 2009.

On June 26, 2009, FirstEnergy announced that seven of its union locals, representing about 2,600 employees, have ratified contract extensions. These unions include employees from Penelec, Penn, CEI, OE and TE, along with certain power plant employees.

On July 8, 2009, FirstEnergy announced that employees of Met-Ed represented by IBEW Local 777 ratified a two-year contract. Union members had been working without a contract since the previous agreement expired on April 30, 2009.

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~~NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

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

In ~~late 2003 and early 2004,~~December 2008, the FASB issued Staff Position FAS 132(R)-1, which provides guidance on an employer’s disclosures about assets of a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. – Canada Power System Outage Task Force) regarding enhancements to regional reliability. The proposed enhancements were divided into two groups: enhancements that were to be completed in 2004; and enhancements that were to be completed after 2004. In 2004, FirstEnergy completed all of the enhancements that were recommended for completion in 2004. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERCdefined benefit pension or other ~~applicable government agencies~~postretirement plan. Requirements of this FSP include disclosures about investment policies and ~~reliability coordinators may, however, take a different view~~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 ~~to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.~~

As a result of ~~outages experienced~~this FSP.

SFAS 166 – “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140”

In June 2009, the FASB issued SFAS 166, which amends the derecognition guidance in ~~JCP&L’s service area~~SFAS 140 and eliminates the concept of a qualifying special-purpose entity (QSPE). It removes the exception from applying FIN 46R to QSPEs and requires an evaluation of all existing QSPEs to determine whether they must be consolidated in ~~2002~~accordance with SFAS 167. This Statement is effective for financial asset transfers that occur in fiscal years beginning after November 15, 2009. FirstEnergy does not expect this Standard to have a material effect upon its financial statements.

SFAS 167 – “Amendments to FASB Interpretation No. 46(R)”

In June 2009, the FASB issued SFAS 167, which amends the consolidation guidance applied to VIEs. This Statement replaces the quantitative approach previously required to determine which entity has a controlling financial interest in a VIE with a qualitative approach. Under the new approach, the primary beneficiary of a VIE is the entity that has both (a) the power to direct the activities of the VIE that most significantly impact the entity’s economic performance, and ~~2003,~~(b) the ~~NJBPU performed~~obligation to absorb losses of the entity, or the right to receive benefits from the entity, that could be significant to the VIE. SFAS 167 also requires ongoing reassessments of whether an entity is the primary beneficiary of a VIE and enhanced disclosures about an entity’s involvement in VIEs. This Statement is effective for fiscal years beginning after November 15, 2009. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

SFAS 168 – “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162”

In June 2009, the FASB issued SFAS 168, which recognizes the FASB Accounting Standards CodificationTM (Codification) as the source of authoritative GAAP. It also recognizes that rules and interpretative releases of the SEC under federal securities laws are sources of authoritative GAAP for SEC registrants. The Codification supersedes all non-SEC accounting and reporting standards. This Statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009. This Statement will change how FirstEnergy references GAAP in its financial statement disclosures.

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 June 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 2009 and 2008. 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 ~~JCP&L’s service reliability. On June 9, 2004,~~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 ~~NJBPU approved~~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 ~~stipulation~~whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications 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 reportshould be made to the ~~NJBPU. On July 14, 2006, JCP&L filed a comprehensive response~~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, 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 ~~consultant’s report with~~accompanying consolidated financial statements, the ~~NJBPU. JCP&L will complete the remaining substantive work described in the stipulation in 2008. JCP&L continues~~Company changed its reporting related to ~~file compliance reports with the NJBPU reflecting JCP&L’s activities associated with implementing the stipulation.~~noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

August 3, 2009

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months						Six Months
	Ended June 30						Ended June 30
	2009			2008			2009			2008
	(In millions, except per share amounts)
REVENUES:
Electric utilities	$	2,791		$	2,865		$	5,811		$	5,778
Unregulated businesses		480			380			794			744
Total revenues *		3,271			3,245			6,605			6,522

EXPENSES:
Fuel		276			316			588			644
Purchased power		1,024			1,070			2,167			2,070
Other operating expenses		612			781			1,439			1,580
Provision for depreciation		185			168			362			332
Amortization of regulatory assets		233			246			642			504
Deferral of regulatory assets		(45	)		(98	)		(136	)		(203	)
General taxes		184			180			395			395
Total expenses		2,469			2,663			5,457			5,322

OPERATING INCOME		802			582			1,148			1,200

OTHER INCOME (EXPENSE):
Investment income		27			16			16			33
Interest expense		(206	)		(188	)		(400	)		(367	)
Capitalized interest		33			13			61			21
Total other expense		(146	)		(159	)		(323	)		(313	)

INCOME BEFORE INCOME TAXES		656			423			825			887

INCOME TAXES		248			160			302			347

NET INCOME		408			263			523			540

Less: Noncontrolling interest income (loss)		(6	)		-			(10	)		1

EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$	414		$	263		$	533		$	539


BASIC EARNINGS PER SHARE OF COMMON STOCK	$	1.36		$	0.86		$	1.75		$	1.77


WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		304			304			304			304


DILUTED EARNINGS PER SHARE OF COMMON STOCK	$	1.36		$	0.85		$	1.75		$	1.75


WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		305			307			306			307


DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	-		$	-		$	0.55		$	0.55


* Includes excise tax collections of $95 million and $100 million in the three months ended June 30, 2009 and 2008, respectively, and
$204 million and $214 million in the six months ended June 2009 and 2008, respectively.

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

3546

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months						Six Months
	Ended June 30						Ended June 30
	2009			2008			2009			2008
	(In millions)

NET INCOME	$	408		$	263		$	523		$	540

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		469			(20	)		504			(40	)
Unrealized gain (loss) on derivative hedges		23			8			38			(5	)
Change in unrealized gain on available-for-sale securities		37			(23	)		32			(81	)
Other comprehensive income (loss)		529			(35	)		574			(126	)
Income tax expense (benefit) related to other comprehensive income		227			(14	)		242			(47	)
Other comprehensive income (loss), net of tax		302			(21	)		332			(79	)

COMPREHENSIVE INCOME		710			242			855			461

LESS: COMPREHENSIVE INCOME ATTRIBUTABLE
TO NONCONTROLLING INTEREST		(6	)		-			(10	)		1

COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	$	716		$	242		$	865		$	460

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)
	June 30,			December 31,
	2009			2008
	(In millions)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	900		$	545
Receivables-
Customers (less accumulated provisions of $26 million and $28 million,
respectively, for uncollectible accounts)		1,313			1,304
Other (less accumulated provisions of $9 million for uncollectible accounts)		127			167
Materials and supplies, at average cost		644			605
Prepaid taxes		457			283
Other		209			149
		3,650			3,053
PROPERTY, PLANT AND EQUIPMENT:
In service		27,315			26,482
Less - Accumulated provision for depreciation		11,113			10,821
		16,202			15,661
Construction work in progress		2,307			2,062
		18,509			17,723
INVESTMENTS:
Nuclear plant decommissioning trusts		1,733			1,708
Investments in lease obligation bonds		553			598
Other		696			711
		2,982			3,017
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,575			5,575
Regulatory assets		2,819			3,140
Power purchase contract asset		214			434
Other		557			579
		9,165			9,728
	$	34,306		$	33,521
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	1,984		$	2,476
Short-term borrowings		2,397			2,397
Accounts payable		806			794
Accrued taxes		259			333
Other		782			1,098
		6,228			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		5,465			5,473
Accumulated other comprehensive loss		(1,048	)		(1,380	)
Retained earnings		4,525			4,159
Total common stockholders' equity		8,973			8,283
Noncontrolling interest		28			32
Total equity		9,001			8,315
Long-term debt and other long-term obligations		10,399			9,100
		19,400			17,415
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,447			2,163
Asset retirement obligations		1,379			1,335
Deferred gain on sale and leaseback transaction		1,010			1,027
Power purchase contract liability		750			766
Retirement benefits		1,473			1,884
Lease market valuation liability		285			308
Other		1,334			1,525
		8,678			9,008
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
	$	34,306		$	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)

	Six Months Ended
	June 30
	2009			2008
	(In millions)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	523		$	540
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		362			332
Amortization of regulatory assets		642			504
Deferral of regulatory assets		(136	)		(203	)
Nuclear fuel and lease amortization		52			51
Deferred purchased power and other costs		(135	)		(95	)
Deferred income taxes and investment tax credits, net		69			129
Investment impairment		39			38
Deferred rents and lease market valuation liability		(59	)		(101	)
Accrued compensation and retirement benefits		(93	)		(140	)
Stock-based compensation		(2	)		(72	)
Gain on asset sales		(12	)		(41	)
Electric service prepayment programs		(10	)		(39	)
Cash collateral, net		48			67
Decrease (increase) in operating assets-
Receivables		32			(136	)
Materials and supplies		6			(31	)
Prepaid taxes		(204	)		(393	)
Increase (decrease) in operating liabilities-
Accounts payable		(11	)		152
Accrued taxes		(101	)		(190	)
Other		92			(53	)
Net cash provided from operating activities		1,102			319

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		1,679			549
Short-term borrowings, net		-			1,705
Redemptions and Repayments-
Long-term debt		(881	)		(719	)
Net controlled disbursement activity		(15	)		8
Common stock dividend payments		(335	)		(335	)
Other		(22	)		19
Net cash provided from financing activities		426			1,227

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(1,143	)		(1,617	)
Proceeds from asset sales		19			56
Sales of investment securities held in trusts		1,001			726
Purchases of investment securities held in trusts		(1,041	)		(775	)
Cash investments		40			65
Other		(49	)		(60	)
Net cash used for investing activities		(1,173	)		(1,605	)

Net change in cash and cash equivalents		355			(59	)
Cash and cash equivalents at beginning of period		545			129
Cash and cash equivalents at end of period	$	900		$	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 supplied, 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.

The demand for electricity produced and sold by FES, along with the value of that electricity, is materially impacted by conditions in competitive power markets, global economic activity, economic activity in the Midwest and Mid-Atlantic regions, and weather conditions in FirstEnergy’s service territories. The current recessionary economic conditions, particularly in the automotive and steel industries, compounded by unusually mild regional summertime temperatures, have directly impacted FES’ operations and revenues.

The level of demand for electricity directly impacts FES’ generation revenues, the quantity of electricity produced, purchased power expense and fuel expense. FirstEnergy and FES have taken various actions and instituted a number of changes in operating practices to mitigate these external influences. These actions include employee severances, wage reductions, employee and retiree benefit changes, reduced levels of overtime and the use of fewer contractors. However, the continuation of recessionary economic conditions, coupled with unusually mild weather patterns and the resulting impact on electricity prices and demand could impact FES’ future operating performance and financial condition and may require further changes in FES’ operations.

Results of Operations

In the first six months of 2009, net income increased to $468 million from $158 million in the same period in 2008. The increase in net income includes FGCO’s $252 million pre-tax gain from the sale of 9% of its participation in OVEC ($158 million after-tax) and an increase in gross sales margins.

Revenues

Revenues increased by $397 million in the first six months of 2009 compared to the same period in 2008 due to the OVEC sale and increases in revenues from non-affiliated and affiliated wholesale sales, partially offset by lower retail generation sales. The increase in revenues resulted from the following sources:

	Six Months Ended
	June 30				Increase
Revenues by Type of Service	2009		2008		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	174	$	315	$	(141	)
Wholesale		311		298		13
Total Non-Affiliated Generation Sales		485		613		(128	)
Affiliated Generation Sales		1,732		1,480		252
Transmission		41		66		(25	)
Sale of OVEC participation interest		252		-		252
Other		57		11		46
Total Revenues	$	2,567	$	2,170	$	397

The lower retail generation revenues resulted from the expiration of certain government aggregation programs in the MISO market at the end of 2008 that were supplied by FES, partially offset by increased retail revenues in both the PJM and MISO markets. The increase in non-aggregation retail revenues in MISO was primarily the result of the acquisition of new customers and higher unit prices. The increase in PJM retail sales resulted from higher unit prices. Higher non-affiliated wholesale revenues resulted from increased sales volumes and prices in MISO partially offset by decreased sales volumes and prices in PJM.

The increase in affiliated company wholesale revenues was due to higher unit prices to the Ohio Companies and increased sales volumes to Met-Ed and Penelec, partially offset by lower sales volumes to the Ohio Companies. The higher unit prices reflected the results of the Ohio Companies’ power procurement processes in the first half of 2009 (see Regulatory Matters – Ohio). In the first quarter of 2009, FES supplied approximately 75% of the Ohio Companies’ power requirements as one of four winning bidders in the Ohio Companies' RFP process. In the second quarter of 2009, FES supplied 100% of the power for the Ohio Companies’ PLR service in April and May 2009, and approximately 56% of the Ohio Companies' supply needs in June 2009. Subsequent to the Ohio Companies’ CBP, FES purchased additional tranches from other winning bidders and effective August 1, 2009, FES will supply 62% of the Ohio Companies’ PLR generation requirements.

Increased sales volumes to the Pennsylvania Companies reflect higher sales to Met-Ed and Penelec, following the expiration of a third-party supply contract for the utilities at the end of 2008, partially offset by lower sales to Penn due to decreased default service requirements in the first six months of 2009 compared to the first six months of 2008. 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.

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated generation sales in the first six 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 57.8% decrease in sales volumes	$	(182	)
Change in prices		41
		(141	)
Wholesale:
Effect of 4.1% decrease in sales volumes		(12	)
Change in prices		25
		13
Net Decrease in Non-Affiliated Generation Revenues	$	(128	)

	Increase
Source of Change in Affiliated Generation Revenues	(Decrease)
	(In millions)
Ohio Companies:
Effect of 19.2% decrease in sales volumes	$	(218	)
Change in prices		449
		231
Pennsylvania Companies:
Effect of 10.6% increase in sales volumes		37
Change in prices		(16	)
		21
Net Increase in Affiliated Generation Revenues	$	252

Transmission revenue decreased $25 million primarily due to reduced retail loads in MISO. Other revenue increased by $46 million principally from rental income associated with NGC's acquisition of additional equity interests in Perry and Beaver Valley Unit 2.

Expenses

Total expenses decreased by $58 million in the first six 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 six 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	$	65
Change due to volume consumed		(118	)
		(53	)
Nuclear Fuel:
Change due to increased unit costs		5
Change due to volume consumed		(7	)
		(2	)
Non-affiliated Purchased Power:
Change due to increased unit costs		22
Change due to volume purchased		(103	)
		(81	)
Affiliated Purchased Power:
Change due to increased unit costs		51
Change due to volume purchased		3
		54
Net Decrease in Fuel and Purchased Power Costs	$	(82	)

Fossil fuel costs decreased $53 million in the first six months of 2009 as a result of decreased coal consumption, reflecting lower generation. Higher unit prices, which are expected to continue during the remainder of 2009, were due to increased fuel costs associated with purchases of eastern coal. Nuclear fuel costs were relatively unchanged in the first six months of 2009 from last year.

Purchased power costs from non-affiliates decreased primarily as a result of reduced volume requirements, partially offset by higher capacity costs. Purchases from affiliated companies increased as a result of higher unit costs on purchases from the OE’s and TE’s leasehold interests in Beaver Valley Unit 2 and Perry.

Other operating expenses increased by $1 million in the first six months of 2009 from the same period of 2008. Higher expenses in the 2009 period for organizational restructuring costs ($4 million), increased nuclear operating costs for an additional refueling outage ($9 million) and higher transmission expenses due to increased charges in the PJM market ($24 million) were offset by lower fossil operating costs ($32 million) and lease expenses ($5 million). Decreased fossil operating costs were primarily due to reduced maintenance activities and more labor dedicated to capital projects compared to the 2008 period. Lower lease expenses were principally due to the transfer of CEI’s and TE’s leasehold improvements for the Mansfield Plant to FGCO during the first quarter of 2008.

Depreciation expense increased by $21 million in the first six months of 2009 primarily due to NGC’s increased ownership interest in Beaver Valley Unit 2 and Perry.

Other Expense

Other expense decreased by $11 million in the first six months of 2009 from the same period of 2008 primarily due to a $12 million decrease in interest expense to affiliates due to lower rates on loans from the unregulated money pool and a $7 million increase in capitalized interest. Partially offsetting the lower interest expense was an $8 million increase in impairments (net of realized investment income) on the nuclear decommissioning trust investments during the 2009 period.

The decrease in FES’ effective income tax rate for the first six months of 2009 is primarily due to the phase out of the Ohio income-based franchise tax at the end of 2008 and an increase in the manufacturing deduction in the 2009 period.

Working Capital

As of June 30, 2009, FES’ net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings and the classification of certain variable interest rate PCRBs as currently payable long-term debt. As of June 30, 2009, FES had access to $1.3 billion of short-term financing under revolving credit facilities. FES also has the ability to borrow from FirstEnergy under the unregulated money pool to meet its short-term working capital requirements.

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 June 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 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

August 3, 2009

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
	(In thousands)

REVENUES:
Electric sales to affiliates	$	839,751		$	704,283		$	1,732,441		$	1,480,590
Electric sales to non-affiliates		205,379			324,276			485,125			612,617
Other		296,022			42,719			349,692			77,187
Total revenues		1,341,152			1,071,278			2,567,258			2,170,394

EXPENSES:
Fuel		270,309			310,550			576,467			632,239
Purchased power from non-affiliates		185,613			220,339			345,955			427,063
Purchased power from affiliates		51,249			34,528			114,456			60,013
Other operating expenses		278,264			287,738			585,620			584,284
Provision for depreciation		65,548			56,160			126,921			105,902
General taxes		21,285			19,795			44,661			42,992
Total expenses		872,268			929,110			1,794,080			1,852,493

OPERATING INCOME		468,884			142,168			773,178			317,901

OTHER INCOME (EXPENSE):
Miscellaneous income (expense)		13,265			(2,074	)		(13,098	)		(4,978	)
Interest expense to affiliates		(3,315	)		(10,728	)		(6,294	)		(17,938	)
Interest expense - other		(26,271	)		(24,505	)		(48,798	)		(49,040	)
Capitalized interest		14,028			10,541			24,106			17,204
Total other expense		(2,293	)		(26,766	)		(44,084	)		(54,752	)

INCOME BEFORE INCOME TAXES		466,591			115,402			729,094			263,149

INCOME TAXES		169,189			47,308			261,011			105,071

NET INCOME		297,402			68,094			468,083			158,078

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		72,121			(1,821	)		74,689			(3,641	)
Unrealized gain (loss) on derivative hedges		15,041			(17,920	)		26,057			(12,202	)
Change in unrealized gain on available-for-sale securities		39,504			(17,709	)		38,027			(69,561	)
Other comprehensive income (loss)		126,666			(37,450	)		138,773			(85,404	)
Income tax expense (benefit) related to other
comprehensive income		50,625			(13,313	)		55,334			(30,716	)
Other comprehensive income (loss), net of tax		76,041			(24,137	)		83,439			(54,688	)

TOTAL COMPREHENSIVE INCOME	$	373,443		$	43,957		$	551,522		$	103,390

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

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	120,034		$	39
Receivables-
Customers (less accumulated provisions of $3,904,000 and $5,899,000,
respectively, for uncollectible accounts)		75,753			86,123
Associated companies		215,362			378,100
Other (less accumulated provisions of $6,702,000 and $6,815,000
respectively, for uncollectible accounts)		19,309			24,626
Notes receivable from associated companies		370,345			129,175
Materials and supplies, at average cost		550,212			521,761
Prepayments and other		98,381			112,535
		1,449,396			1,252,359
PROPERTY, PLANT AND EQUIPMENT:
In service		10,226,785			9,871,904
Less - Accumulated provision for depreciation		4,400,182			4,254,721
		5,826,603			5,617,183
Construction work in progress		2,019,748			1,747,435
		7,846,351			7,364,618
INVESTMENTS:
Nuclear plant decommissioning trusts		1,040,410			1,033,717
Long-term notes receivable from associated companies		-			62,900
Other		29,212			61,591
		1,069,622			1,158,208
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		151,457			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		74,281			69,932
Other		62,305			96,434
		433,751			579,836
	$	10,799,120		$	10,355,021
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	1,632,264		$	2,024,898
Short-term borrowings-
Associated companies		309,832			264,823
Other		1,100,000			1,000,000
Accounts payable-
Associated companies		367,395			472,338
Other		168,485			154,593
Accrued taxes		68,759			79,766
Other		180,990			248,439
		3,827,725			4,244,857
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 750 shares,
7 shares outstanding		1,463,074			1,464,229
Accumulated other comprehensive loss		(8,432	)		(91,871	)
Retained earnings		2,040,148			1,572,065
Total common stockholder's equity		3,494,790			2,944,423
Long-term debt and other long-term obligations		965,677			571,448
		4,460,467			3,515,871
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		1,009,727			1,026,584
Accumulated deferred investment tax credits		60,562			62,728
Asset retirement obligations		891,505			863,085
Retirement benefits		131,882			194,177
Property taxes		50,104			50,104
Lease market valuation liability		284,952			307,705
Other		82,196			89,910
		2,510,928			2,594,293
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	10,799,120		$	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)

	Six Months Ended
	June 30
	2009			2008
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	468,083		$	158,078
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		126,921			105,902
Nuclear fuel and lease amortization		53,265			51,207
Deferred rents and lease market valuation liability		(55,493	)		(52,537	)
Deferred income taxes and investment tax credits, net		63,309			51,961
Investment impairment		36,154			33,533
Accrued compensation and retirement benefits		(10,594	)		(8,399	)
Commodity derivative transactions, net		17,688			3,705
Gain on asset sales		(9,635	)		(8,836	)
Cash collateral, net		40,471			(5,355	)
Decrease (increase) in operating assets:
Receivables		179,373			(86,773	)
Materials and supplies		16,609			(27,867	)
Prepayments and other current assets		7,555			(14,512	)
Increase (decrease) in operating liabilities:
Accounts payable		(102,907	)		(37,794	)
Accrued taxes		(14,333	)		(98,948	)
Accrued interest		1,871			(1,603	)
Other		(6,121	)		(16,743	)
Net cash provided from operating activities		812,216			45,019

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		681,675			455,735
Short-term borrowings, net		145,009			1,652,643
Redemptions and Repayments-
Long-term debt		(622,853	)		(458,377	)
Common stock dividend payments		-			(10,000	)
Net cash provided from financing activities		203,831			1,640,001

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(634,967	)		(1,152,502	)
Proceeds from asset sales		15,771			10,875
Sales of investment securities held in trusts		537,078			384,692
Purchases of investment securities held in trusts		(550,730	)		(404,502	)
Loans to associated companies, net		(241,170	)		(461,496	)
Other		(22,034	)		(62,087	)
Net cash used for investing activities		(896,052	)		(1,685,020	)

Net change in cash and cash equivalents		119,995			-
Cash and cash equivalents at beginning of period		39			2
Cash and cash equivalents at end of period	$	120,034		$	2

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

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 six months of 2009, net income decreased to $45 million from $93 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.

Revenues

Revenues increased by $159 million, or 12.6%, in the first six months of 2009 compared with the same period in 2008, primarily due to increases in retail generation revenues ($213 million) and wholesale revenues ($59 million), partially offset by decreases in distribution throughput revenues ($109 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 service territory. Average prices increased primarily due to an increase in OE's fuel cost recovery rider that was effective from January through May 2009. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under OE’s CBP.

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

Retail Generation KWH Sales	Increase (Decrease)

Residential		12.9	%
Commercial		19.1	%
Industrial		(10.8	)%
Net Increase in Generation Sales		6.9	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	98
Commercial		83
Industrial		32
Increase in Generation Revenues	$	213

Revenues from distribution throughput decreased by $109 million in the first six 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 reflect 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 six months of 2009 from the same period in 2008 are summarized in the following tables.

Distribution KWH Deliveries	Decrease

Residential		(0.9	)%
Commercial		(3.6	)%
Industrial		(25.8	)%
Decrease in Distribution Deliveries		(10.4	)%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(14	)
Commercial		(44	)
Industrial		(51	)
Decrease in Distribution Revenues	$	(109	)

Expenses

Total expenses increased by $223 million in the first six 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	$	235
Other operating costs		(8	)
Provision for depreciation		1
Amortization of regulatory assets, net		(3	)
General taxes		(2	)
Net Increase in Expenses	$	223

Higher purchased power costs reflect the results of OE’s power procurement process for retail customers in the first six months of 2009 (see Regulatory Matters – Ohio) and higher volumes due to increased retail generation KWH sales. The decrease in other operating costs for the first six months of 2009 was primarily due to lower MISO transmission expenses (included in the cost of power purchased from others beginning June 1, 2009), partially offset by accruals for economic development programs and energy efficiency obligations. Lower amortization of net regulatory assets was primarily due to the conclusion of transition cost recovery in 2008, partially offset by lower MISO transmission cost deferrals and lower RCP distribution deferrals. The decrease in general taxes for the first six months of 2009 was primarily due to lower Ohio KWH taxes.

Other Expenses

Other expenses increased by $11 million in the first six months of 2009 compared to the same period in 2008 primarily due to higher interest expense associated with the issuance of $300 million of FMBs by OE in October 2008.

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 OE.

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 OE.

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 June 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 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

August 3, 2009

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended							Six Months Ended
	June 30							June 30
	2009			2008				2009			2008
	(In thousands)
STATEMENTS OF INCOME

REVENUES:
Electric sales	$	647,224		$	583,268			$	1,367,235		$	1,205,539
Excise and gross receipts tax collections		24,948			26,287				53,928			56,665
Total revenues		672,172			609,555				1,421,163			1,262,204

EXPENSES:
Purchased power from affiliates		314,870			280,024				647,206			599,735
Purchased power from non-affiliates		98,330			28,025				236,143			48,500
Other operating costs		111,938			137,619				269,768			277,945
Provision for depreciation		21,996			21,414				43,509			42,907
Amortization of regulatory assets, net		22,295			21,955				42,506			45,082
General taxes		43,903			44,389				93,023			94,842
Total expenses		613,332			533,426				1,332,155			1,109,011

OPERATING INCOME		58,840			76,129				89,008			153,193

OTHER INCOME (EXPENSE):
Investment income		10,149			11,488				19,511			26,543
Miscellaneous income (expense)		2,681			(126	)			1,871			(3,778	)
Interest expense		(21,469	)		(16,901	)			(44,756	)		(34,542	)
Capitalized interest		279			159				499			269
Total other expense		(8,360	)		(5,380	)			(22,875	)		(11,508	)

INCOME BEFORE INCOME TAXES		50,480			70,749				66,133			141,685

INCOME TAXES		16,852			21,748				20,857			48,621

NET INCOME		33,628			49,001				45,276			93,064

Less: Noncontrolling interest income		143			159				289			313

EARNINGS AVAILABLE TO PARENT	$	33,485		$	48,842			$	44,987		$	92,751

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	33,628		$	49,001			$	45,276		$	93,064

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		89,864			(3,994	)			95,602			(7,988	)
Change in unrealized gain on available-for-sale securities		728			(2,803	)			(1,981	)		(10,374	)
Other comprehensive income (loss)		90,592			(6,797	)			93,621			(18,362	)
Income tax expense (benefit) related to other comprehensive income		37,310			(2,564	)			37,839			(6,826	)
Other comprehensive income (loss), net of tax		53,282			(4,233	)			55,782			(11,536	)

COMPREHENSIVE INCOME		86,910			44,768				101,058			81,528

COMPREHENSIVE INCOME ATTRIBUTABLE
TO NONCONTROLLING INTEREST		143			159		��		289			313

COMPREHENSIVE INCOME AVAILABLE TO PARENT	$	86,767		$	44,609			$	100,769		$	81,215

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)
	June 30,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	223,812		$	146,343
Receivables-
Customers (less accumulated provisions of $6,186,000 and $6,065,000, respectively,
for uncollectible accounts)		289,084			277,377
Associated companies		244,266			234,960
Other (less accumulated provisions of $99,000 and $7,000, respectively,
for uncollectible accounts)		12,970			14,492
Notes receivable from associated companies		172,061			222,861
Prepayments and other		19,027			5,452
		961,220			901,485
UTILITY PLANT:
In service		2,956,467			2,903,290
Less - Accumulated provision for depreciation		1,135,811			1,113,357
		1,820,656			1,789,933
Construction work in progress		37,385			37,766
		1,858,041			1,827,699
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		193,071			256,974
Investment in lease obligation bonds		230,150			239,625
Nuclear plant decommissioning trusts		117,523			116,682
Other		97,807			100,792
		638,551			714,073
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		514,415			575,076
Property taxes		60,542			60,542
Unamortized sale and leaseback costs		37,629			40,130
Other		33,290			33,710
		645,876			709,458
	$	4,103,688		$	4,152,715
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	2,715		$	101,354
Short-term borrowings-
Associated companies		114,771			-
Other		1,386			1,540
Accounts payable-
Associated companies		78,944			131,725
Other		74,371			26,410
Accrued taxes		77,974			77,592
Accrued interest		25,709			25,673
Other		95,689			85,209
		471,559			449,503
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 shares outstanding		1,224,398			1,224,416
Accumulated other comprehensive loss		(128,603	)		(184,385	)
Retained earnings		174,010			254,023
Total common stockholder's equity		1,269,805			1,294,054
Noncontrolling interest		6,835			7,106
Total equity		1,276,640			1,301,160
Long-term debt and other long-term obligations		1,160,609			1,122,247
		2,437,249			2,423,407
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		681,972			653,475
Accumulated deferred investment tax credits		12,335			13,065
Asset retirement obligations		83,261			80,647
Retirement benefits		216,661			308,450
Other		200,651			224,168
		1,194,880			1,279,805
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	4,103,688		$	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)

	Six Months Ended
	June 30
	2009			2008
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	45,276		$	93,064
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		43,509			42,907
Amortization of regulatory assets, net		42,506			45,082
Purchased power cost recovery reconciliation		11,068			-
Amortization of lease costs		(4,540	)		(4,399	)
Deferred income taxes and investment tax credits, net		(11,252	)		7,059
Accrued compensation and retirement benefits		(4,593	)		(31,579	)
Accrued regulatory obligations		18,350			-
Electric service prepayment programs		(4,603	)		(21,771	)
Cash collateral from suppliers		6,380			-
Decrease (increase) in operating assets-
Receivables		(16,509	)		30,159
Prepayments and other current assets		(6,290	)		(2,485	)
Increase (decrease) in operating liabilities-
Accounts payable		(4,820	)		(6,831	)
Accrued taxes		(19,523	)		(31,306	)
Accrued interest		36			(1,252	)
Other		10,086			2,798
Net cash provided from operating activities		105,081			121,446

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		100,000			-
Short-term borrowings, net		114,617			69,573
Redemptions and Repayments-
Long-term debt		(100,984	)		(175,572	)
Dividend Payments-
Common stock		(125,000	)		(50,000	)
Other		(1,627	)		(445	)
Net cash used for financing activities		(12,994	)		(156,444	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(69,512	)		(92,061	)
Sales of investment securities held in trusts		24,941			79,613
Purchases of investment securities held in trusts		(30,877	)		(84,130	)
Loan repayments from associated companies, net		51,803			123,905
Cash investments		7,929			5,000
Other		1,098			2,828
Net cash provided from (used for) investing activities		(14,618	)		35,155

Net increase in cash and cash equivalents		77,469			157
Cash and cash equivalents at beginning of period		146,343			732
Cash and cash equivalents at end of period	$	223,812		$	889

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 experienced a net loss of $58 million in the first six months of 2009 compared to net income of $125 million in the same period of 2008. The loss in 2009 resulted primarily from regulatory charges ($228 million) related to the implementation of CEI's ESP. The 2009 results were also adversely impacted by increased purchased power costs, partially offset by higher deferrals of new regulatory assets, increased revenues and lower other operating costs.

Revenues

Revenues increased by $53 million, or 6.1%, in the first six months of 2009 compared to the same period of 2008 primarily due to an increase in retail generation revenues ($81 million), partially offset by a decrease in distribution revenues ($19 million) and other miscellaneous revenues ($9 million).

Retail generation revenues increased in the first six months of 2009 due to higher average unit prices in all customer classes and increased sales volume to residential and commercial customers, compared to the same period of 2008. Average prices increased due to an increase in CEI’s fuel cost recovery rider that was effective from January through May 2009, and effective June 1, 2009, the transmission tariff ended, with transmission services now included in the generation rate established under CEI's CBP. Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions. The increase in sales volumes for residential and commercial customers resulted from a decrease in customer shopping, as most of CEI’s customers returned to PLR service in December 2008 following the termination of certain government aggregation programs in CEI’s service territory.

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

	Increase
Retail Generation KWH Sales	(Decrease)

Residential		8.3 %
Commercial		14.6 %
Industrial		(8.6)%
Increase in Retail Generation Sales		2.0 %

Retail Generation Revenues	Increase
	(in millions)
Residential	$	27
Commercial		34
Industrial		20
Increase in Generation Revenues	$	81

Revenues from distribution throughput decreased by $19 million in the first six months of 2009 compared to the same period of 2008 due to a decrease in KWH deliveries, partially offset by higher average unit prices in the commercial and industrial sectors. The higher average unit prices was the net result of a PUCO-approved distribution rate increase effective May 1, 2009, partially offset by reduced transition rates (see Regulatory Matters – Ohio). The lower KWH deliveries in the first six months of 2009 were due to economic conditions. Cooling degree days in the first six months of 2009 were 17% lower than in the previous year, while heating degree days increased slightly.

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

Distribution KWH Deliveries	Decrease

Residential		(0.5) %
Commercial		(3.6) %
Industrial		(19.1) %
Decrease in Distribution Deliveries		(9.8) %


Distribution Revenues	Decrease
	(In millions)
Residential	$	(10	)
Commercial		(3	)
Industrial		(6	)
Decrease in Distribution Revenues	$	(19	)

Expenses

Total expenses increased by $333 million in the first six 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	$	225
Other operating costs		(24	)
Amortization of regulatory assets		209
Deferral of new regulatory assets		(79	)
General Taxes		2
Net Increase in Expenses	$	333

Higher purchased power costs reflect the results of CEI’s power procurement process for retail customers in the first six months of 2009 (see Regulatory Matters – Ohio). Increased amortization of regulatory assets was primarily due to the impairment of CEI’s Extended RTC balance ($216 million) in accordance with the PUCO-approved ESP. The increase in the deferral of new regulatory assets was 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. Other operating costs were $24 million lower than in the previous year due to lower transmission expenses (included in the cost of power purchased from others beginning June 1, 2009) and reduced labor and contractor costs, partially offset by costs associated with the ESP for economic development and energy efficiency programs, higher pension expense and restructuring costs. The increase in general taxes was primarily due to higher 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 June 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 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

August 3, 2009

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
STATEMENTS OF INCOME	(In thousands)

REVENUES:
Electric sales	$	458,287		$	418,194		$	889,692		$	836,902
Excise tax collections		16,799			16,195			35,119			34,795
Total revenues		475,086			434,389			924,811			871,697

EXPENSES:
Purchased power from affiliates		243,499			185,483			482,371			375,679
Purchased power from non-affiliates		49,414			128			121,160			3,176
Other operating costs		39,177			62,659			104,007			127,777
Provision for depreciation		17,852			17,744			36,132			36,820
Amortization of regulatory assets		29,580			38,525			286,317			76,781
Deferral of new regulatory assets		(39,771	)		(26,019	)		(134,587	)		(55,267	)
General taxes		36,856			32,425			74,997			72,508
Total expenses		376,607			310,945			970,397			637,474

OPERATING INCOME (LOSS)		98,479			123,444			(45,586	)		234,223

OTHER INCOME (EXPENSE):
Investment income		7,614			8,394			16,034			17,582
Miscellaneous income (expense)		798			(280	)		2,792			838
Interest expense		(32,757	)		(30,935	)		(66,079	)		(63,455	)
Capitalized interest		51			188			118			384
Total other expense		(24,294	)		(22,633	)		(47,135	)		(44,651	)

INCOME (LOSS) BEFORE INCOME TAXES		74,185			100,811			(92,721	)		189,572

INCOME TAX EXPENSE (BENEFIT)		26,461			33,779			(35,045	)		64,105

NET INCOME (LOSS)		47,724			67,032			(57,676	)		125,467

Less: Noncontrolling interest income		419			459			877			1,043

EARNINGS (LOSS) AVAILABLE TO PARENT	$	47,305		$	66,573		$	(58,553	)	$	124,424

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME (LOSS)	$	47,724		$	67,032		$	(57,676	)	$	125,467

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		43,903			(213	)		47,870			(426	)
Income tax expense (benefit) related to other comprehensive income		17,936			(390	)		19,306			(109	)
Other comprehensive income (loss), net of tax		25,967			177			28,564			(317	)

COMPREHENSIVE INCOME (LOSS)		73,691			67,209			(29,112	)		125,150

COMPREHENSIVE INCOME ATTRIBUTABLE
TO NONCONTROLLING INTEREST		419			459			877			1,043

COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT	$	73,272		$	66,750		$	(29,989	)	$	124,107

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)
	June 30,				December 31,
		2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	230		$	226
Receivables-
Customers (less accumulated provisions of $6,252,000 and
$5,916,000, respectively, for uncollectible accounts)			317,526			276,400
Associated companies			158,425			113,182
Other			11,934			13,834
Notes receivable from associated companies			24,510			19,060
Prepayments and other			3,933			2,787
			516,558			425,489
UTILITY PLANT:
In service			2,258,897			2,221,660
Less - Accumulated provision for depreciation			870,038			846,233
			1,388,859			1,375,427
Construction work in progress			40,553			40,651
			1,429,412			1,416,078
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			388,645			425,715
Other			10,227			10,249
			398,872			435,964
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			1,688,521			1,688,521
Regulatory assets			628,068			783,964
Property taxes			71,500			71,500
Other			10,343			10,818
			2,398,432			2,554,803
		$	4,743,274		$	4,832,334
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	150,721		$	150,688
Short-term borrowings-
Associated companies			293,574			227,949
Accounts payable-
Associated companies			61,603			106,074
Other			45,657			7,195
Accrued taxes			63,500			87,810
Accrued interest			14,165			13,932
Other			47,890			40,095
			677,110			633,743
CAPITALIZATION:
Common stockholder's equity
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding			878,735			878,785
Accumulated other comprehensive loss			(106,293	)		(134,857	)
Retained earnings			801,401			859,954
Total common stockholder's equity			1,573,843			1,603,882
Noncontrolling interest			20,592			22,555
Total equity			1,594,435			1,626,437
Long-term debt and other long-term obligations			1,573,094			1,591,586
			3,167,529			3,218,023
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			665,370			704,270
Accumulated deferred investment tax credits			12,433			13,030
Retirement benefits			90,331			128,738
Lease assignment payable to associated companies			40,827			40,827
Other			89,674			93,703
			898,635			980,568
COMMITMENTS AND CONTINGENCIES (Note 8)
		$	4,743,274		$	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)

	Six Months Ended
	June 30
	2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(57,676	)	$	125,467
Adjustments to reconcile net income (loss) to net cash from operating activities-
Provision for depreciation		36,132			36,820
Amortization of regulatory assets		286,317			76,781
Deferral of new regulatory assets		(134,587	)		(55,267	)
Purchased power cost recovery reconciliation		2,072			-
Deferred income taxes and investment tax credits, net		(58,506	)		(12,125	)
Accrued compensation and retirement benefits		2,092			(4,027	)
Accrued regulatory obligations		12,057			-
Electric service prepayment programs		(3,510	)		(11,498	)
Cash collateral from suppliers		5,365			-
Decrease (increase) in operating assets-
Receivables		(84,469	)		73,484
Prepayments and other current assets		(1,145	)		(689	)
Increase (decrease) in operating liabilities-
Accounts payable		18,991			11,076
Accrued taxes		(29,434	)		(38,654	)
Accrued interest		232			178
Other		3,265			4,203
Net cash provided from (used for) operating activities		(2,804	)		205,749

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		47,423			-
Redemptions and Repayments-
Long-term debt		(368	)		(335	)
Short-term borrowings, net		-			(100,562	)
Dividend Payments-
Common stock		(25,000	)		(100,000	)
Other		(3,019	)		(2,955	)
Net cash provided from (used for) financing activities		19,036			(203,852	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(46,434	)		(67,206	)
Loan repayments from (loans to) associated companies, net		(5,449	)		30,132
Redemption of lessor notes		37,070			37,712
Other		(1,415	)		(2,528	)
Net cash used for investing activities		(16,228	)		(1,890	)

Net increase in cash and cash equivalents		4			7
Cash and cash equivalents at beginning of period		226			232
Cash and cash equivalents at end of period	$	230		$	239

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 six months of 2009 decreased to $7 million from $38 million in the same period of 2008. The decrease resulted primarily from the completion of transition cost recovery in 2008.

Revenues

Revenues increased $38 million, or 8.7%, in the first six months of 2009 compared to the same period of 2008 primarily due to increased retail generation revenues ($117 million), partially offset by lower distribution revenues ($70 million) and wholesale generation revenues ($11 million).

Retail generation revenues increased in the first six 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. Average prices increased primarily due to an increase in TE's fuel cost recovery rider that was effective from January through May 2009. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under TE’s CBP. 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 from a decrease in customer shopping. Most of TE’s customers returned to PLR service in December 2008, following the termination of certain government aggregation programs in TE’s service territory.

The decrease in wholesale revenues was due to the expiration of a sales agreement with AMP-Ohio at the end of 2008 ($6 million) and lower revenues from associated company sales to NGC ($5 million) from TE’s leasehold interest in Beaver Valley Unit 2.

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

	Increase
Retail Generation KWH Sales	(Decrease)

Residential		8.1	%
Commercial		39.1	%
Industrial		(13.5	)%
Net Increase in Retail Generation Sales		2.6	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	28
Commercial		51
Industrial		38
Increase in Retail Generation Revenues	$	117

Revenues from distribution throughput decreased by $70 million in the first six months of 2009 compared to the same period of 2008 due to lower average unit prices and lower KWH deliveries for all customer classes due primarily to economic conditions. 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).

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

Distribution KWH Deliveries	Decrease

Residential		(2.0	)%
Commercial		(8.7	)%
Industrial		(15.7	)%
Decrease in Distribution Deliveries		(10.5	)%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(14	)
Commercial		(35	)
Industrial		(21	)
Decrease in Distribution Revenues	$	(70	)

Expenses

Total expenses increased $83 million in the first six 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	$	111
Other operating costs		(16	)
Provision for depreciation		(2	)
Amortization of regulatory assets, net		(10	)
Net Increase in Expenses	$	83

Higher purchased power costs reflect the results of TE’s power procurement process for retail customers in the first six months of 2009 (see Regulatory Matters – Ohio). Other operating costs decreased primarily due to reduced transmission expenses (included in the cost of power purchased from others beginning June 1, 2009) and lower costs associated with TE’s leasehold interest in Beaver Valley Unit 2 (absence of a refueling outage in the 2009 period). These reductions were partially offset by cost increases associated with regulatory obligations for economic development and energy efficiency programs. 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 completion of transition cost recovery, partially offset by a reduction in transmission cost deferrals and the absence of RCP distribution cost deferrals in 2009.

Legal Proceedings

New Accounting Standards and Interpretations

~~In 2005, Congress amended~~

Report of Independent Registered Public Accounting Firm

To the ~~Federal Power Act to provide~~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 June 30, 2009 and the related consolidated statements of income and comprehensive income for ~~federally-enforceable mandatory reliability standards. The mandatory reliability~~each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

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

Based on our review, we are not aware of any material modifications that should be made to the ~~bulk power system and impose certain operating, record-keeping and reporting requirements on the Companies and ATSI. The NERC is charged~~accompanying consolidated interim financial statements for them to be in conformity with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including the Reliability~~First~~ ~~Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst~~ ~~region. FirstEnergy actively participates~~accounting principles generally accepted in the ~~NERC~~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, 2008, and ~~ReliabilityFirst~~ ~~stakeholder processes,~~the related consolidated statements of income, capitalization, common stockholder's equity, and ~~otherwise monitors~~cash flows for the year then ended (not presented herein), and ~~manages its companies~~ in ~~response~~our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 6 to the ~~ongoing development, implementation~~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

August 3, 2009

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
	(In thousands)
STATEMENTS OF INCOME

REVENUES:
Electric sales	$	219,911		$	214,353		$	456,996		$	418,022
Excise tax collections		6,297			7,153			14,026			15,178
Total revenues		226,208			221,506			471,022			433,200

EXPENSES:
Purchased power from affiliates		130,564			102,773			255,888			202,267
Purchased power from non-affiliates		18,244			77			58,781			1,881
Other operating costs		35,480			50,805			80,484			96,134
Provision for depreciation		7,717			7,941			15,289			16,966
Amortization of regulatory assets, net		11,771			16,431			21,668			31,962
General taxes		12,349			12,605			26,599			26,982
Total expenses		216,125			190,632			458,709			376,192

OPERATING INCOME		10,083			30,874			12,313			57,008

OTHER INCOME (EXPENSE):
Investment income		7,529			5,224			13,013			11,705
Miscellaneous income (expense)		1,375			(1,947	)		35			(3,459	)
Interest expense		(9,262	)		(5,578	)		(14,795	)		(11,613	)
Capitalized interest		50			88			92			125
Total other expense		(308	)		(2,213	)		(1,655	)		(3,242	)

INCOME BEFORE INCOME TAXES		9,775			28,661			10,658			53,766

INCOME TAXES		3,370			7,352			3,261			15,440

NET INCOME		6,405			21,309			7,397			38,326

Less: Noncontrolling interest income		1			2			3			4

EARNINGS AVAILABLE TO PARENT	$	6,404		$	21,307		$	7,394		$	38,322

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	6,405		$	21,309		$	7,397		$	38,326

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		19,016			(64	)		19,149			(127	)
Change in unrealized gain on available-for-sale securities		(2,739	)		(2,481	)		(3,548	)		(520	)
Other comprehensive income (loss)		16,277			(2,545	)		15,601			(647	)
Income tax expense (benefit) related to other comprehensive income		7,224			(914	)		7,205			(186	)
Other comprehensive income (loss), net of tax		9,053			(1,631	)		8,396			(461	)

COMPREHENSIVE INCOME		15,458			19,678			15,793			37,865

COMPREHENSIVE INCOME ATTRIBUTABLE
TO NONCONTROLLING INTEREST		1			2			3			4

COMPREHENSIVE INCOME AVAILABLE TO PARENT	$	15,457		$	19,676		$	15,790		$	37,861

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)
	June 30,				December 31,
		2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	319,454		$	14
Receivables-
Customers			508			751
Associated companies			64,734			61,854
Other (less accumulated provisions of $192,000 and $203,000,
respectively, for uncollectible accounts)			19,978			23,336
Notes receivable from associated companies			131,556			111,579
Prepayments and other			5,193			1,213
			541,423			198,747
UTILITY PLANT:
In service			891,108			870,911
Less - Accumulated provision for depreciation			417,418			407,859
			473,690			463,052
Construction work in progress			8,065			9,007
			481,755			472,059
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			124,357			142,687
Long-term notes receivable from associated companies			37,075			37,233
Nuclear plant decommissioning trusts			73,696			73,500
Other			1,625			1,668
			236,753			255,088
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			500,576			500,576
Regulatory assets			91,407			109,364
Property taxes			22,970			22,970
Other			66,161			51,315
			681,114			684,225
		$	1,941,045		$	1,610,119
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	222		$	34
Accounts payable-
Associated companies			31,622			70,455
Other			24,178			4,812
Notes payable to associated companies			171,180			111,242
Accrued taxes			25,777			24,433
Lease market valuation liability			36,900			36,900
Other			23,311			22,489
			313,190			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			175,883			175,879
Accumulated other comprehensive loss			(24,976	)		(33,372	)
Retained earnings			197,927			190,533
Total common stockholder's equity			495,844			480,050
Noncontrolling interest			2,678			2,675
Total equity			498,522			482,725
Long-term debt and other long-term obligations			600,430			299,626
			1,098,952			782,351
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			85,343			78,905
Accumulated deferred investment tax credits			6,585			6,804
Lease market valuation liability			254,650			273,100
Retirement benefits			57,734			73,106
Asset retirement obligations			31,234			30,213
Lease assignment payable to associated companies			30,529			30,529
Other			62,828			64,746
			528,903			557,403
COMMITMENTS AND CONTINGENCIES (Note 8)
		$	1,941,045		$	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)

	Six Months Ended
	June 30
	2009			2008
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	7,397		$	38,326
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		15,289			16,966
Amortization of regulatory assets, net		21,668			31,962
Purchased power cost recovery reconciliation		(4,197	)		-
Deferred rents and lease market valuation liability		(40,697	)		(39,045	)
Deferred income taxes and investment tax credits, net		(1,206	)		(3,113	)
Accrued compensation and retirement benefits		711			(1,160	)
Accrued regulatory obligations		4,450			-
Electric service prepayment programs		(1,458	)		(6,017	)
Cash collateral from suppliers		2,755			-
Decrease (increase) in operating assets-
Receivables		1,075			76,978
Prepayments and other current assets		(220	)		(292	)
Increase (decrease) in operating liabilities-
Accounts payable		5,533			(166,120	)
Accrued taxes		(2,936	)		(7,923	)
Accrued interest		3,983			-
Other		1,788			866
Net cash provided from (used for) operating activities		13,935			(58,572	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		297,422			-
Short-term borrowings, net		59,938			21,558
Redemptions and Repayments-
Long-term debt		(236	)		(17	)
Dividend Payments-
Common stock		(25,000	)		(35,000	)
Other		(247	)		-
Net cash provided from (used for) financing activities		331,877			(13,459	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(21,661	)		(34,388	)
Loan repayments from (loans to) associated companies, net		(19,819	)		97,614
Redemption of lessor notes		18,330			11,959
Sales of investment securities held in trusts		77,323			21,791
Purchases of investment securities held in trusts		(78,700	)		(23,581	)
Other		(1,845	)		(1,364	)
Net cash provided from (used for) investing activities		(26,372	)		72,031

Net change in cash and cash equivalents		319,440			-
Cash and cash equivalents at beginning of period		14			22
Cash and cash equivalents at end of period	$	319,454		$	22

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 ~~enforcement~~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 ~~reliability standards.~~first six months of 2009 decreased to $66 million from $77 million in the same period in 2008. The decrease was primarily due to lower revenues, partially offset by lower purchased power costs and reduced amortization of regulatory assets.

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

In ~~April 2007, ReliabilityFirst~~ ~~performed a routine compliance audit~~the first six months of ~~FirstEnergy’s bulk-power system within~~2009, revenues decreased by $147 million, or 9%, compared with the ~~Midwest ISO region~~same period of 2008. Retail and ~~found it~~wholesale generation revenues decreased by $3 million and $124 million, respectively, and distribution revenues decreased by $14 million in the first six months of 2009.

Retail generation revenues decreased due to belower retail generation KWH sales in ~~full compliance with~~ all ~~audited reliability standards. Similarly, ReliabilityFirst~~ ~~has scheduled a compliance audit~~sectors, partially offset by higher unit prices in the residential and commercial sectors resulting from the BGS auctions effective June 1, 2008, and June 1, 2009. Lower sales to the residential sector reflected milder weather in JCP&L’s service territory, while the decrease in sales to the commercial sector was primarily due to an increase in the number of ~~FirstEnergy’s bulk-power system within the PJM region in 2008. FirstEnergy currently does not expect any material adverse financial impact~~shopping customers. Industrial sales were lower as a result of ~~these audits.~~weakened economic conditions.

Wholesale generation revenues decreased $124 million in the first six months of 2009 due to lower market prices and a decrease in sales volume from NUG purchases resulting from the termination of a NUG contract in October 2008.

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

Retail Generation KWH Sales	Decrease

Residential		(3.5)	%
Commercial		(13.6)	%
Industrial		(6.6)	%
Decrease in Generation Sales		(7.7)	%

Retail Generation Revenues	Increase (Decrease)
	(In millions)
Residential	$	29
Commercial		(27	)
Industrial		(5	)
Net Decrease in Generation Revenues	$	(3	)

Distribution revenues decreased $14 million in the first six months of 2009 compared to the same period of 2008 due to lower KWH deliveries, reflecting weather and economic impacts in JCP&L’s service territory, partially offset by an increase in composite unit prices.

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

Distribution KWH Deliveries	Decrease

Residential		(3.5)	%
Commercial		(3.3)	%
Industrial		(12.6)	%
Decrease in Distribution Deliveries		(4.6)	%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(8	)
Commercial		(5	)
Industrial		(1	)
Decrease in Distribution Revenues	$	(14	)

Expenses

Total expenses decreased by $135 million in the first six 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	$	(126	)
Provision for depreciation		4
Amortization of regulatory assets		(11	)
General taxes		(2	)
Net decrease in expenses	$	(135	)

Purchased power costs decreased in the first six months of 2009 primarily due to the lower KWH sales requirements discussed above, partially offset by higher unit prices resulting from the BGS auction process. Depreciation expense increased due to an increase in depreciable property since the second quarter of 2008. Amortization of regulatory assets decreased in the first six months of 2009 primarily due to the full recovery of certain regulatory assets in June 2008. General taxes decreased principally as the result of lower sales taxes.

Other Expenses

~~(B) OHIO~~Other expenses increased by $7 million in the first six months of 2009 compared to the same period in 2008 primarily due to higher interest expense associated with JCP&L's $300 million Senior Notes issuance in January 2009.

Sale of Investment

On April 17, 2008, JCP&L closed on the sale of its 86-MW Forked River Power Plant to Maxim Power Corp. for $20 million, as approved by an earlier order from the NJBPU. The New Jersey Rate Counsel appealed the sale to the Appellate Division of the Superior Court of New Jersey. On July 10, 2009, the Court upheld the NJBPU’s order and the sale of the plant.

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 June 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 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

August 3, 2009

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
	(In thousands)

REVENUES:
Electric sales	$	697,061		$	823,104		$	1,457,981		$	1,604,537
Excise tax collections		11,031			11,639			23,762			24,434
Total revenues		708,092			834,743			1,481,743			1,628,971

EXPENSES:
Purchased power		423,950			534,177			905,191			1,030,858
Other operating costs		70,876			77,569			156,746			156,353
Provision for depreciation		25,301			23,543			50,404			46,825
Amortization of regulatory assets		80,018			86,507			166,849			178,026
General taxes		12,587			15,538			30,083			32,566
Total expenses		612,732			737,334			1,309,273			1,444,628

OPERATING INCOME		95,360			97,409			172,470			184,343

OTHER INCOME (EXPENSE):
Miscellaneous income		2,007			1,413			2,812			1,024
Interest expense		(29,671	)		(24,840	)		(57,539	)		(49,304	)
Capitalized interest		218			430			280			706
Total other expense		(27,446	)		(22,997	)		(54,447	)		(47,574	)

INCOME BEFORE INCOME TAXES		67,914			74,412			118,023			136,769

INCOME TAXES		29,848			31,468			52,399			59,871

NET INCOME		38,066			42,944			65,624			76,898

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		20,918			(3,449	)		25,039			(6,898	)
Unrealized gain on derivative hedges		69			69			138			138
Other comprehensive income (loss)		20,987			(3,380	)		25,177			(6,760	)
Income tax expense (benefit) related to other comprehensive income		11,059			(1,469	)		12,489			(2,939	)
Other comprehensive income (loss), net of tax		9,928			(1,911	)		12,688			(3,821	)

TOTAL COMPREHENSIVE INCOME	$	47,994		$	41,033		$	78,312		$	73,077

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)
	June 30,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	138		$	66
Receivables-
Customers (less accumulated provisions of $3,158,000 and $3,230,000
respectively, for uncollectible accounts)		315,553			340,485
Associated companies		166			265
Other		21,337			37,534
Notes receivable - associated companies		17,595			16,254
Prepaid taxes		156,503			10,492
Other		17,598			18,066
		528,890			423,162
UTILITY PLANT:
In service		4,386,758			4,307,556
Less - Accumulated provision for depreciation		1,582,136			1,551,290
		2,804,622			2,756,266
Construction work in progress		57,080			77,317
		2,861,702			2,833,583
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		192,585			181,468
Nuclear plant decommissioning trusts		146,098			143,027
Other		2,163			2,145
		340,846			326,640
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,810,936			1,810,936
Regulatory assets		1,055,327			1,228,061
Other		24,978			29,946
		2,891,241			3,068,943
	$	6,622,679		$	6,652,328
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	29,831		$	29,094
Short-term borrowings-
Associated companies		65,113			121,380
Accounts payable-
Associated companies		14,863			12,821
Other		177,379			198,742
Accrued taxes		7,258			20,561
Accrued interest		18,570			9,197
Other		108,311			133,091
		421,325			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		2,502,675			2,644,756
Accumulated other comprehensive loss		(203,850	)		(216,538	)
Retained earnings		134,200			156,576
Total common stockholder's equity		2,569,309			2,729,010
Long-term debt and other long-term obligations		1,817,960			1,531,840
		4,387,269			4,260,850
NONCURRENT LIABILITIES:
Power purchase contract liability		474,533			531,686
Accumulated deferred income taxes		680,159			689,065
Nuclear fuel disposal costs		196,357			196,235
Asset retirement obligations		98,365			95,216
Retirement benefits		172,668			190,182
Other		192,003			164,208
		1,814,085			1,866,592
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	6,622,679		$	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)

	Six Months Ended
	June 30
	2009			2008
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	65,624		$	76,898
Adjustments to reconcile net income to net cash from operating activities -
Provision for depreciation		50,404			46,825
Amortization of regulatory assets		166,849			178,026
Deferred purchased power and other costs		(50,542	)		(69,247	)
Deferred income taxes and investment tax credits, net		3,440			(8,656	)
Accrued compensation and retirement benefits		(2,883	)		(28,695	)
Cash collateral received from (returned to) suppliers		(209	)		66,040
Decrease (increase) in operating assets-
Receivables		41,228			(79,001	)
Prepaid taxes		(146,011	)		(137,006	)
Other current assets		271			534
Increase (decrease) in operating liabilities-
Accounts payable		(19,321	)		96,297
Accrued taxes		(14,007	)		(1,972	)
Accrued interest		9,373			(54	)
Tax collections payable		(9,714	)		(12,493	)
Other		4,555			(14,194	)
Net cash provided from operating activities		99,057			113,302

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		299,619			-
Short-term borrowings, net		-			164,358
Redemptions and Repayments-
Long-term debt		(13,093	)		(12,012	)
Common Stock		(150,000	)		-
Short-term borrowings, net		(56,267	)		-
Dividend Payments-
Common stock		(88,000	)		(176,000	)
Other		(2,260	)		(67	)
Net cash used for financing activities		(10,001	)		(23,721	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(78,401	)		(98,068	)
Proceeds from asset sales		-			20,000
Loans to associated companies, net		(1,341	)		(653	)
Sales of investment securities held in trusts		244,880			113,970
Purchases of investment securities held in trusts		(252,856	)		(122,324	)
Other		(1,266	)		(2,368	)
Net cash used for investing activities		(88,984	)		(89,443	)

Net increase in cash and cash equivalents		72			138
Cash and cash equivalents at beginning of period		66			94
Cash and cash equivalents at end of period	$	138		$	232

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 $27 million in the first six months of 2009, compared to $42 million in the same period of 2008. The decrease was primarily due to increased amortization of regulatory assets, partially offset by higher revenues and lower other operating costs.

Revenues

Revenues increased by $15 million, or 1.9%, in the first six months of 2009, compared to the same period of 2008, primarily due to higher distribution throughput revenues, partially offset by a decrease in retail generation and wholesale revenues. Wholesale revenues decreased by $1 million in the first six months of 2009 due to lower wholesale KWH sales volume, partially offset by higher capacity prices for PJM market participants.

In the first six months of 2009, retail generation revenues decreased $17 million due to lower KWH sales to all classes with a slight increase in composite unit prices in all customer classes. Lower KWH sales to commercial and industrial customers were principally due to economic conditions in Met-Ed’s service territory. Lower KWH sales in the residential sector were due to decreased weather-related usage, reflecting a 22.5% decrease in cooling degree days in the first six months of 2009 and a 2.5% decrease in heating degree days in the second quarter of 2009.

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


Retail Generation KWH Sales	(Decrease)

Residential		(0.2	)%
Commercial		(4.3	)%
Industrial		(13.6	)%
Decrease in Retail Generation Sales		(5.3	)%


Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	-
Commercial		(5	)
Industrial		(12	)
Decrease in Retail Generation Revenues	$	(17	)

In the first six months of 2009, distribution throughput revenues increased $38 million primarily due to higher transmission rates, resulting from the annual updates to Met-Ed’s TSC rider in June 2008 and 2009. Decreased deliveries to commercial and industrial customers reflected the weakened economy, while decreased deliveries to residential customers were a result of the weather conditions described above.

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


Distribution KWH Deliveries	(Decrease)

Residential		(0.2	)%
Commercial		(4.3	)%
Industrial		(13.6	)%
Decrease in Distribution Deliveries		(5.3	)%

Distribution Revenues	Increase
	(In millions)
Residential	$	22
Commercial		11
Industrial		5
Increase in Distribution Revenues	$	38

PJM transmission service revenues decreased by $5 million in the first six months of 2009 compared to the same period of 2008, primarily due to decreased revenues related to Met-Ed’s 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 $33 million in the first six months 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	$	(9	)
Other operating costs		(66	)
Provision for depreciation		3
Amortization of regulatory assets, net		103
General taxes		2
Net Increase in Expenses	$	33

The net amortization of regulatory assets increased by $103 million in the first six months of 2009 compared to the same period of 2008 primarily due to increased transmission cost recovery reflecting lower PJM transmission service expenses and the increased transmission revenues described above. Other operating costs decreased $66 million in the first six months of 2009 primarily due to lower transmission expenses as a result of decreased congestion costs and transmission loss expenses. Purchased power costs decreased by $9 million, or 2.0%, in the first six months of 2009 due to reduced volume as a result of lower KWH sales requirements, partially offset by an increase in composite unit prices. Depreciation expense increased primarily due to an increase in depreciable property since the second quarter of 2008.

Other Expense

Other expense increased in the first six months of 2009 primarily due to a decrease in interest earned 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 June 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 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

August 3, 2009

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
	(In thousands)

REVENUES:
Electric sales	$	360,022		$	373,821		$	769,708		$	753,429
Gross receipts tax collections		17,586			18,158			37,569			38,876
Total revenues		377,608			391,979			807,277			792,305

EXPENSES:
Purchased power from affiliates		78,652			68,209			178,729			151,651
Purchased power from non-affiliates		123,299			149,534			247,210			283,074
Other operating costs		51,309			117,028			157,666			224,045
Provision for depreciation		12,919			10,940			25,058			22,052
Amortization (deferral) of regulatory assets, net		61,548			(11,645	)		89,139			(13,842	)
General taxes		22,034			20,076			43,969			41,857
Total expenses		349,761			354,142			741,771			708,837

OPERATING INCOME		27,847			37,837			65,506			83,468

OTHER INCOME (EXPENSE):
Interest income		2,769			4,873			5,955			10,352
Miscellaneous income		1,058			789			1,914			480
Interest expense		(14,763	)		(10,980	)		(28,122	)		(22,652	)
Capitalized interest		62			199			77			(20	)
Total other expense		(10,874	)		(5,119	)		(20,176	)		(11,840	)

INCOME BEFORE INCOME TAXES		16,973			32,718			45,330			71,628

INCOME TAXES		6,968			12,921			18,703			29,596

NET INCOME		10,005			19,797			26,627			42,032

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		27,369			(2,233	)		31,922			(4,466	)
Unrealized gain on derivative hedges		84			84			168			168
Other comprehensive income (loss)		27,453			(2,149	)		32,090			(4,298	)
Income tax expense (benefit) related to other comprehensive income		13,592			(971	)		15,385			(1,941	)
Other comprehensive income (loss), net of tax		13,861			(1,178	)		16,705			(2,357	)

TOTAL COMPREHENSIVE INCOME	$	23,866		$	18,619		$	43,332		$	39,675

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)
	June 30,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	125		$	144
Receivables-
Customers (less accumulated provisions of $3,421,000 and $3,616,000,
respectively, for uncollectible accounts)		163,556			159,975
Associated companies		20,145			17,034
Other		12,387			19,828
Notes receivable from associated companies		317,894			11,446
Prepaid taxes		46,403			6,121
Other		4,595			1,621
		565,105			216,169
UTILITY PLANT:
In service		2,116,595			2,065,847
Less - Accumulated provision for depreciation		794,738			779,692
		1,321,857			1,286,155
Construction work in progress		17,763			32,305
		1,339,620			1,318,460
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		233,289			226,139
Other		976			976
		234,265			227,115
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		416,499			416,499
Regulatory assets		496,902			412,994
Power purchase contract asset		183,639			300,141
Other		34,308			31,031
		1,131,348			1,160,665
	$	3,270,338		$	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		29,094			28,707
Other		36,319			55,330
Accrued taxes		14,484			16,238
Accrued interest		16,985			6,755
Other		27,754			30,647
		503,136			431,180
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,500 shares outstanding		1,196,136			1,196,172
Accumulated other comprehensive loss		(124,279	)		(140,984	)
Accumulated deficit		(24,496	)		(51,124	)
Total common stockholder's equity		1,047,361			1,004,064
Long-term debt and other long-term obligations		713,812			513,752
		1,761,173			1,517,816
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		429,032			387,757
Accumulated deferred investment tax credits		7,540			7,767
Nuclear fuel disposal costs		44,356			44,328
Asset retirement obligations		174,424			170,999
Retirement benefits		121,326			145,218
Power purchase contract liability		161,106			150,324
Other		68,245			67,020
		1,006,029			973,413
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	3,270,338		$	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)

	Six Months Ended
	June 30
	2009			2008
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	26,627		$	42,032
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		25,058			22,052
Amortization (deferral) of regulatory assets, net		89,139			(13,842	)
Deferred costs recoverable as regulatory assets		(47,592	)		(12,468	)
Deferred income taxes and investment tax credits, net		30,135			29,113
Accrued compensation and retirement benefits		3,250			(14,819	)
Cash collateral		(6,800	)		-
Decrease (Increase) in operating assets-
Receivables		346			(31,840	)
Prepayments and other current assets		(39,068	)		(25,316	)
Increase (decrease) in operating liabilities-
Accounts payable		(18,624	)		7,411
Accrued taxes		(1,754	)		(14,451	)
Accrued interest		10,230			31
Other		7,870			7,608
Net cash provided from (used for) operating activities		78,817			(4,489	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		300,000			28,500
Short-term borrowings, net		-			72,485
Redemptions and Repayments-
Long-term debt		-			(28,637	)
Short-term borrowings, net		(15,003	)		-
Other		(2,267	)		-
Net cash provided from financing activities		282,730			72,348

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(48,464	)		(62,011	)
Sales of investment securities held in trusts		63,086			81,538
Purchases of investment securities held in trusts		(67,668	)		(87,193	)
Loans from (to) associated companies, net		(306,448	)		395
Other		(2,072	)		(593	)
Net cash used for investing activities		(361,566	)		(67,864	)

Net decrease in cash and cash equivalents		(19	)		(5	)
Cash and cash equivalents at beginning of period		144			135
Cash and cash equivalents at end of period	$	125		$	130

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 $34 million in the first six months of 2009, compared to $40 million in the same period of 2008. The decrease was primarily due to lower revenues, partially offset by lower purchased power costs and decreased amortization of regulatory assets.

Revenues

Revenues decreased by $27 million, or 3.6%, in the first six months of 2009 primarily due to lower retail generation revenues and PJM transmission revenues, partially offset by higher wholesale generation revenues and distribution throughput revenues. Wholesale revenues increased $3 million in the first six months of 2009, compared to the same period of 2008, primarily reflecting higher KWH sales.

In the first six months of 2009, retail generation revenues decreased $19 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 six months of 2009 compared to the same period of 2008 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)

Residential		0.3	%
Commercial		(2.9	)%
Industrial		(16.9	)%
Net Decrease in Retail Generation Sales		(6.1	)%


Retail Generation Revenues	Decrease
	(In millions)
Residential	$	-
Commercial		(4	)
Industrial		(15	)
Decrease in Retail Generation Revenues	$	(19	)

Revenues from distribution throughput increased $5 million in the first six months 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 six months of 2009 compared to the same period of 2008 are summarized in the following tables:

Distribution KWH Deliveries	Increase (Decrease)

Residential		0.3	%
Commercial		(2.9	)%
Industrial		(16.4	)%
Net Decrease in Distribution Deliveries		(6.3	)%

Distribution Revenues	Increase (Decrease)
	(In millions)
Residential	$	5
Commercial		1
Industrial		(1	)
Net Increase in Distribution Revenues	$	5

PJM transmission revenues decreased by $20 million in the first six months 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 decreased by $7 million in the first six months 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	$	(6	)
Other operating costs		2
Provision for depreciation		4
Amortization of regulatory assets, net		(5	)
General taxes		(2	)
Net Decrease in Expenses	$	(7	)

Purchased power costs decreased by $6 million, or 1.5%, in the first six months of 2009 compared to the same period of 2008 due to reduced volume as a result of lower KWH sales requirements, partially offset by increased composite unit prices. Other operating costs increased by $2 million in the first six months of 2009 due primarily to higher pension and OPEB expenses. Depreciation expense increased primarily due to an increase in depreciable property since the second quarter of 2008. The net amortization of regulatory assets decreased in the first six months of 2009 primarily due to increased transmission cost deferrals as a result of increased net congestion costs.

Other Expense

In the first six months of 2009, other expense decreased primarily due to lower interest expense on borrowings from the regulated money pool combined with reduced interest expense on long-term debt due to the $100 million repayment of unsecured notes in April 2009.

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 June 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 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

August 3, 2009

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
	(In thousands)
REVENUES:
Electric sales	$	316,881		$	335,382		$	688,174		$	711,410
Gross receipts tax collections		14,804			16,040			32,096			35,504
Total revenues		331,685			351,422			720,270			746,914

EXPENSES:
Purchased power from affiliates		72,166			62,568			168,247			146,032
Purchased power from non-affiliates		125,317			143,223			252,483			280,993
Other operating costs		46,301			50,100			123,590			121,177
Provision for depreciation		15,581			13,918			30,036			26,434
Amortization of regulatory assets, net		18,113			19,111			26,889			31,931
General taxes		18,251			18,345			38,844			40,200
Total expenses		295,729			307,265			640,089			646,767

OPERATING INCOME		35,956			44,157			80,181			100,147

OTHER INCOME (EXPENSE):
Miscellaneous income		911			1,058			1,709			867
Interest expense		(11,843	)		(14,901	)		(25,076	)		(30,223	)
Capitalized interest		29			70			51			(736	)
Total other expense		(10,903	)		(13,773	)		(23,316	)		(30,092	)

INCOME BEFORE INCOME TAXES		25,053			30,384			56,865			70,055

INCOME TAXES		10,232			11,987			23,354			30,266

NET INCOME		14,821			18,397			33,511			39,789

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		29,400			(3,474	)		32,355			(6,947	)
Unrealized gain on derivative hedges		16			16			32			32
Change in unrealized gain on available-for-sale securities		6			(21	)		(16	)		(10	)
Other comprehensive income (loss)		29,422			(3,479	)		32,371			(6,925	)
Income tax expense (benefit) related to other comprehensive income		15,100			(1,520	)		16,155			(3,026	)
Other comprehensive income (loss), net of tax		14,322			(1,959	)		16,216			(3,899	)

TOTAL COMPREHENSIVE INCOME	$	29,143		$	16,438		$	49,727		$	35,890

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)
	June 30,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11		$	23
Receivables-
Customers (less accumulated provisions of $2,889,000 and $3,121,000,
respectively, for uncollectible accounts)		129,092			146,831
Associated companies		55,221			65,610
Other		11,976			26,766
Notes receivable from associated companies		14,770			14,833
Prepaid taxes		53,095			16,310
Other		482			1,517
		264,647			271,890
UTILITY PLANT:
In service		2,371,657			2,324,879
Less - Accumulated provision for depreciation		884,685			868,639
		1,486,972			1,456,240
Construction work in progress		28,105			25,146
		1,515,077			1,481,386
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		122,343			115,292
Non-utility generation trusts		118,302			116,687
Other		287			293
		240,932			232,272
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		768,628			768,628
Power purchase contract asset		21,347			119,748
Regulatory assets		9,911			-
Other		15,106			18,658
		814,992			907,034
	$	2,835,648		$	2,892,582
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	45,000		$	145,000
Short-term borrowings-
Associated companies		178,056			31,402
Other		250,000			250,000
Accounts payable-
Associated companies		27,055			63,692
Other		40,162			48,633
Accrued taxes		5,490			13,264
Accrued interest		11,462			13,131
Other		23,395			31,730
		580,620			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		912,420			912,441
Accumulated other comprehensive loss		(111,781	)		(127,997	)
Retained earnings		109,624			76,113
Total common stockholder's equity		998,815			949,109
Long-term debt and other long-term obligations		633,259			633,132
		1,632,074			1,582,241
NONCURRENT LIABILITIES:
Regulatory liabilities		-			136,579
Accumulated deferred income taxes		210,952			169,807
Retirement benefits		146,751			172,718
Asset retirement obligations		88,852			87,089
Power purchase contract liability		114,164			83,600
Other		62,235			63,696
		622,954			713,489
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	2,835,648		$	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)

	Six Months Ended
	June 30
	2009			2008
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	33,511		$	39,789
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		30,036			26,434
Amortization of regulatory assets, net		26,889			31,931
Deferred costs recoverable as regulatory assets		(46,349	)		(13,288	)
Deferred income taxes and investment tax credits, net		24,700			12,760
Accrued compensation and retirement benefits		490			(16,293	)
Cash collateral		2			301
Decrease (increase) in operating assets-
Receivables		42,494			(11,082	)
Prepayments and other current assets		(35,750	)		(33,370	)
Increase (decrease) in operating liabilities-
Accounts payable		(10,108	)		(9,438	)
Accrued taxes		(7,629	)		(11,804	)
Accrued interest		(1,669	)		-
Other		2,302			9,714
Net cash provided from operating activities		58,919			25,654

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			45,000
Short-term borrowings, net		146,654			96,880
Redemptions and Repayments-
Long-term debt		(100,000	)		(45,320	)
Dividend Payments-
Common stock		(35,000	)		(55,000	)
Net cash provided from financing activities		11,654			41,560

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(59,606	)		(57,314	)
Loan repayments from (loans to) associated companies, net		63			(151	)
Sales of investment securities held in trust		53,504			45,108
Purchases of investment securities held in trust		(60,378	)		(53,537	)
Other		(4,168	)		(1,328	)
Net cash used for investing activities		(70,585	)		(67,222	)

Net decrease in cash and cash equivalents		(12	)		(8	)
Cash and cash equivalents at beginning of period		23			46
Cash and cash equivalents at end of period	$	11		$	38

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)

·	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 income as incurred. Regulatory assets that do not earn a current return totaled approximately $158 million as of June 30, 2009 (JCP&L - $48 million, Met-Ed - $95 million and Penelec - $15 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 and Penelec. The following table discloses net regulatory assets by company:

	June 30,		December 31,		Increase
Regulatory Assets	2009		2008		(Decrease)
	(In millions)
OE	$	514	$	575	$	(61	)
CEI		628		784		(156	)
TE		91		109		(18	)
JCP&L		1,055		1,228		(173	)
Met-Ed		497		413		84
Penelec*		10		-		10
ATSI		24		31		(7	)
Total	$	2,819	$	3,140	$	(321	)

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

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

On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10,June 7, 2007, the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider, with alternative options for the recovery period ranging from five to twenty-five years. This second application is currently pending before the PUCO and a hearing has been set for July 15, 2008.

~~The Ohio Companies filed an application and rate request~~ for an increase in electric distribution rates with the PUCO ~~on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect~~ and, would result in lowering the overall non-generation portion of the average electric bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operation and maintenance expenses and recovery of regulatory assets that were authorized in prior cases. Onon August 6, 2007, ~~the Ohio Companies~~ updated their filing ~~supporting~~to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of ~~their~~its investigation into the distribution rate request. ~~In its reports,~~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 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. This amount excludes the recovery of deferred fuel costs, whose recovery is now being sought in a separate proceeding before the PUCO, discussed above. On January 3, 2008,this order were filed by the Ohio Companies and ~~intervening parties filed objections~~one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.

SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the ~~Staff Reports and on January 10,~~filing of an MRO. On July 31, 2008, the Ohio Companies filed ~~supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings,~~with the PUCO ~~Staff submitted testimony decreasing their recommended revenue increase~~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, which is still pending. The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a ~~range~~three-year period and resolve the Ohio Companies’ collection of ~~$114 million~~fuel costs deferred in 2006 and 2007, and the distribution rate request described above. In response to ~~$132 million. Additionally,~~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 ~~testimony submitted on February 11,~~addition to continuing their current rate plan in effect as allowed by the terms of SB221. On December 31, 2008, the ~~PUCO Staff adopted~~Ohio Companies conducted a ~~position regarding interest deferred~~CBP for ~~RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by~~ the ~~PUCO, would result in the write-off~~procurement of ~~approximately $45 million of interest costs deferred~~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 provided generation service to the Ohio Companies’ retail customers who chose 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 ~~($0.09 per share of common stock).~~CBP. The PUCO ~~is expected~~ultimately approved the Ohio Companies’ request for a new fuel rider to ~~render its decision during~~recover increased costs resulting from the ~~second or third quarter of 2008.~~CBP but denied OE’s and TE’s request to continue collecting RTC and denied the request to allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new ~~rates would become effective January 1, 2009~~fuel rider recovered the increased purchased power costs for OE and TE, and ~~approximately May 2009~~recovered a portion of those costs for ~~CEI.~~

CEI, with the remainder being deferred for future recovery.

On ~~July 10, 2007,~~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 provided that generation would 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 would be based upon the outcome of a descending clock CBP on a slice-of-system basis. The Amended ESP further provided 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 would agree to write-off approximately $216 million of its Extended RTC balance, and that the Ohio Companies would 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 addressed a number of other issues, including but not limited to, rate design for various customer classes, and 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, 2009 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 took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009.

On July 27, 2009, the Ohio Companies filed applications with the PUCO ~~requesting approval~~to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a ~~comprehensive supply plan~~5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for ~~providing~~these deferrals is a total of $298.4 million. If the applications are approved, recovery of this amount, together with carrying charges calculated as approved in the Amended ESP, will be collected in the 18 non-summer months from September 2009 through May 2011, subject to reconciliation until fully collected, with $165 million of the above amount being recovered from residential customers, and $133.4 million being recovered from non-residential customers. Pursuant to the applications, customers would pay significantly less over the life of the recovery of the deferral through the reduction in carrying charges as compared to the expected recovery under the previously approved recovery mechanism.

As a result of the CBP auction, FES expects to sell less of its generation output to its affiliated utilities in 2009 and 2010 than it has done historically. By 2011, FES' supply obligations to its affiliated Pennsylvania utilities expire pursuant to the terms of the existing partial requirements wholesale power agreement, with all of its output expected to be subject to market-based generation pricing. Accordingly, FES continues to focus on expanding its retail opportunities and has recently increased retail sales to governmental aggregation groups in Ohio and large industrial customers both inside and outside of Ohio. As of August 1, 2009, FES has signed 50 government aggregation contracts that will provide discounted generation prices ~~resulting from~~to approximately 600,000 residential and small commercial customers. The governmental aggregator may choose between a graduated or flat percentage discount. When FES' sales to the governmental aggregation groups are combined with all ~~bids. In their filing,~~of its other committed sales, including its position in the Ohio ~~Companies offered two alternatives for structuring the bids, either by customer class or~~auction, FES' total generation hedged as a ~~“slice-of-system” approach. A slice-of-system approach would require the successful bidder~~percentage of forecasted output is expected to be ~~responsible for supplying a fixed percentage of the utility’s total load notwithstanding the customer’s classification. The proposal provides the PUCO with an option to phase~~93% in ~~generation price increases for residential tariff groups who would experience a change~~2009 and 76% in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Initial and reply comments on the proposal were filed by various parties in September and October 2007, respectively. The proposal is currently pending before the PUCO.2010.

~~On April 22, 2008, an amended version of Substitute~~ SB221 was passed by the Ohio House of Representatives and sent back to the Ohio Senate for concurrence. On April 23, 2008, the Ohio Senate approved the House's amendments to Substitute SB221 and forwarded the bill to the Governor for signature, which he signed on May 1, 2008. Amended Substitute SB221also requires ~~all~~ electric distribution utilities to ~~file an RSP, now called an ESP, with the PUCO. An ESP is~~implement energy efficiency programs that achieve a total annual 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 ~~contain a proposal for the supply~~reduce peak demand in 2009 by 1%, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. Additionally, electric utilities and ~~pricing~~electric service companies are required to serve part of ~~retail generation and may include proposals, without limitation, related~~their load from renewable energy resources equivalent to ~~one or more~~0.25% of the ~~following:~~KWH they serve in 2009. FirstEnergy has efforts underway to address compliance with these requirements. Costs associated with compliance are recoverable from customers.

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

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

·	~~costs of an electric generating facility;~~

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

·	~~accounting for deferrals related to stabilizing retail electric service;~~

·	~~automatic increases or decreases in standard service offer price;~~

·	~~phase-in and securitization;~~

·	~~transmission service and related costs;~~

·	~~distribution service and related costs; and~~

·	~~economic development and energy efficiency.~~

~~A utility could also simultaneously file an MRO in which it would have to demonstrate~~On June 17, 2009, the ~~following objective market criteria: The utility or its transmission service affiliate belongs to a FERC-approved RTO having a market-monitor function~~PUCO modified rules that implement the alternative energy portfolio standards created by SB221, including the incorporation of energy efficiency requirements, long-term forecast and ~~the ability to mitigate market power,~~greenhouse gas reporting and ~~a published source exists that identifies information for traded electricity and energy products that are contracted for delivery two years into the future.~~CO2 control planning. The PUCO ~~would test~~filed the ~~ESP~~rules with the Joint Committee on Agency Rule Review on July 7, 2009, after which begins a 65-day review period. The Ohio Companies and ~~its pricing and all~~one other ~~terms and conditions against~~party filed applications for rehearing on the ~~MRO and may only approve the ESP if it is found to be more favorable to customers. As part of an ESP~~rules with ~~a plan period longer than three years,~~ the PUCO ~~shall prospectively determine every fourth year of the plan whether it is substantially likely the plan will provide the electric distribution utility a return~~ on common equity significantly in excess of the return likely to be earned by publicly traded companies, including utilities, that face comparable business and financial risk (comparable companies). If so, the PUCO may terminate the ESP. Annually under an ESP, the PUCO shall determine whether an electric distribution utility's earned return on common equity is significantly in excess of returns earned on common equity during the same period by comparable companies, and if so, shall require the utility to return such excess to customers by prospective adjustments. Amended Substitute SB221 also includes provisions dealing with advanced and renewable energy standards that contemplate 25% of electrical usage from these sources by 2025. Energy efficiency measures in the bill require energy savings in excess of 22% by 2025. Requirements are in place to meet annual benchmarks for renewable energy resources and energy efficiency, subject to review by the PUCO. FirstEnergy is currently evaluating this legislation and expects to file an ESP in the second or third quarter of 2008.July 17, 2009.

~~(C) PENNSYLVANIA~~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. ~~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.

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).material.

On ~~March 30, 2007, MEIUG and PICA filed a Petition for Review with~~May 22, 2008, the ~~Commonwealth Court of Pennsylvania asking~~PPUC approved 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 April 14, 2008, Met-Ed and Penelec filed~~ 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 ~~proposed~~ TSCs ~~include~~included 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 ~~has proposed~~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 March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. On April 14, 2008, the first RFP for residential customers’ load was held consisting of tranches for both 12 and 24-month supply. The PPUC approved the bids on April 16, 2008. The second RFP is scheduled to be held on May 14, 2008, after which time the PPUC is expected to approve the new rates to go into effect June 1, 2008.

3896

On ~~February 1, 2007,~~October 15, 2008, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 into law which ~~provides for~~became effective on November 14, 2008 as Act 129 of 2008. Act 129 addresses issues such as: energy efficiency and ~~demand management programs~~peak load reduction; generation procurement; time-of-use rates; smart meters; and ~~targets as well as~~alternative energy. 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 prudent 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;

·	utilities must reduce peak demand by a minimum of 4.5% by May 31, 2013;

·	utilities must reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and

·	the definition of Alternative Energy was expanded to include additional types of hydroelectric and biomass facilities.

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 ~~smart meters within ten years. Other legislation has been introduced~~utilities’ energy efficiency and peak load reduction plans. On June 18, 2009, the PPUC issued its guidelines related to ~~address generation procurement,~~Smart Meter deployment. On July 1, 2009, Met-Ed, Penelec, and Penn filed Energy Efficiency and Conservation Plans with the PPUC in accordance with Act 129.

Legislation addressing rate mitigation and the expiration of rate caps ~~conservation and renewable energy.~~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 ~~this pending~~such legislation is uncertain. ~~Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.~~

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

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, ~~and~~ costs incurred under NUG agreements, 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, 2008,~~June 30, 2009, the accumulated deferred cost balance totaled approximately ~~$264~~$149 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 ~~August 1, 2005,~~March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU ~~established~~that includes 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 preventrequest for 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,reduction in the ~~same proceeding,~~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 Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 with comments from interested parties due on May 16, 2008.NJBPU.

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

~~On April 17, 2008, a draft~~The EMP was ~~released for public comment. The draft EMP establishes four~~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 (amounting to about a 22% reduction in projected demand);~~2020;

meet ~~22.5%~~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

~~develop low carbon emitting, efficient power plants~~invest in innovative clean energy technologies and ~~close~~businesses to stimulate the ~~gap between the supply and demand for electricity.~~industry’s growth in New Jersey.

~~Following~~On January 28, 2009, the ~~public comment period which is expected~~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 ~~extend into July 2008, a final EMP will be issued to be followed by appropriate legislation and regulation as necessary.~~achieve the goals of the EMP. At this time, ~~FirstEnergy~~JCP&L 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.~~operations.

On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published inIn support of the New Jersey ~~Register, which~~Governor's Economic Assistance and Recovery Plan, JCP&L announced a proposal ~~will~~to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. Under the proposal, an estimated $40 million would be ~~subsequently considered by the NJBPU following comments~~spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. Approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million would be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent on energy efficiency programs that ~~were submitted in September and October 2007. Final regulations (effective upon publication) were published in the New Jersey Register March 17, 2008. Upon preliminary review~~would complement those currently being offered. Implementation of the ~~new regulations, FirstEnergy does not expect a material impact on its operations or those~~projects is dependent upon resolution of ~~JCP&L.~~regulatory issues including recovery of the costs associated with the proposal.

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

PJM Transmission Rate ~~Design~~

On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate ~~design;~~design, notably AEP, which proposed to create a "postage ~~stamp",~~stamp," or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. ~~This~~AEP's 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.

The FERC’s orders on PJM rate design ~~will~~would 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~~would reduce the costs of future transmission ~~revenue recovery~~to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” 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 ~~will proceed to~~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

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 was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10, 2009.

Changes ordered for PJM Reliability Pricing Model (RPM) Auction

MISO Resource Adequacy Proposal

100

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 a December 23, 2008 waiver of restrictions on affiliate sales without prior approval of the FERC.

On May 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate in the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES was the successful bidder for 51 tranches, and subsequently purchased 11 additional tranches from other bidders. The auction resulted in an overall weighted average wholesale price of 6.15 cents per KWH for generation and transmission. The new prices for PLR service went into effect with usage beginning June 1, 2009, and continuing through May 31, 2011.

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.

101

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.

102

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. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allege 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 seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. 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 and Connecticut’s 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 1, 2009, the Court held oral argument on Met-Ed’s motion to dismiss the complaint.

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 (Applicable to FES)

In March 2005, the EPA finalized 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 2.5 million tons annually and NOX emissions to 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. On July 10, 2009, the United States Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the "8-hour" ozone NAAQS. FGCO's 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.

103

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 any future regulations 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)

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 House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. 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.

104

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 June 30, 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 $104 million (JCP&L - - $77 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through June 30, 2009. Included in the total are accrued liabilities of approximately $68 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. 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 due to the outages.

105

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. On March 31, 2009, the trial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was granted by the Appellate Division on June 15, 2009. According to the scheduling order issued by the Appellate Division, Plaintiffs' opening brief is due on August 25, 2009, JCP&L's opposition brief is due on September 25, 2009, and Plaintiffs' reply is due on October 5, 2009.

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 June 8, 2009, the NRC issued the final Safety Evaluation Report (SER) supporting the renewed license for Beaver Valley Units 1 and 2. On July 8, 2009, the NRC’s Advisory Committee on Reactor Safeguards (ACRS) held a public meeting to consider the NRC’s final SER. Much of the ACRS’ discussion involved questions raised by a letter from Citizens Power regarding the extent of corrective actions for the 2009 discovery of a penetration in the Beaver Valley Unit 1 containment liner. On July 28, 2009, FENOC submitted to the NRC further clarifications on the supplemental volumetric examinations of Beaver Valley’s containment liners. FENOC anticipates another meeting with the ACRS regarding the container liner during September 2009. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and is scheduled 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.

106

The bargaining unit employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. On July 24, 2009, FirstEnergy declared that bargaining was at an impasse and portions of its last contract offer were implemented August 1, 2009. A federal mediator is continuing to assist the parties in reaching a negotiated contract settlement. FirstEnergy 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 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 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. FES and the Utilities will expand their disclosures related to postretirement benefit plan assets as a result of this FSP.

SFAS 166 – “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140”

In June 2009, the FASB issued SFAS 166, which amends the derecognition guidance in SFAS 140 and eliminates the concept of a qualifying special-purpose entity (QSPE). It removes the exception from applying FIN 46R to QSPEs and requires an evaluation of all existing QSPEs to determine whether they must be consolidated in accordance with SFAS 167. This Statement is effective for financial asset transfers that occur in fiscal years beginning after November 15, 2009. FES and the Utilities do not expect this Standard to have a material effect upon their financial statements.

SFAS 167 – “Amendments to FASB Interpretation No. 46(R)”

In June 2009, the FASB issued SFAS 167, which amends the consolidation guidance applied to VIEs. This Statement replaces the quantitative approach previously required to determine which entity has a controlling financial interest in a VIE with a qualitative approach. Under the new approach, the primary beneficiary of a VIE is the entity that has both (a) the power to direct the activities of the VIE that most significantly impact the entity’s economic performance, and (b) the obligation to absorb losses of the entity, or the right to receive benefits from the entity, that could be significant to the VIE. SFAS 167 also requires ongoing reassessments of whether an entity is the primary beneficiary of a VIE and enhanced disclosures about an entity’s involvement in VIEs. This Statement is effective for fiscal years beginning after November 15, 2009. FES and the Utilities are currently evaluating the impact of adopting this Standard on their financial statements.

SFAS 168 – “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162”

In June 2009, the FASB issued SFAS 168, which recognizes the FASB Accounting Standards CodificationTM (Codification) as the source of authoritative GAAP. It also recognizes that rules and interpretative releases of the SEC under federal securities laws are sources of authoritative GAAP for SEC registrants. The Codification supersedes all non-SEC accounting and reporting standards. This Statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009. This Statement will change how FES and the Utilities reference GAAP in their financial statement disclosures.

107

Debt Capacity and Financing Activities (Applicable to FES and each of the Utilities)

Long-Term Debt Capacity

Met-Ed and Penelec had the capability to issue secured debt of approximately $428 million and $310 million, respectively, under provisions of their senior note indentures as of June 30, 2009.

FES' and the Utilities’ access to capital markets and costs of financing are influenced by the ratings of their securities and those of FirstEnergy. The following table displays FirstEnergy's, FES' and the Utilities' securities ratings as of June 30, 2009. On June 17, 2009, Moody's affirmed FirstEnergy’s Baa3 and FES' Baa2 credit ratings. On July 9, 2009, S&P affirmed its ratings on FirstEnergy and its subsidiaries. S&P's and Moody's outlook for FirstEnergy and its subsidiaries remains "stable."

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

108

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. On July 29, 2009, FES registered its common stock pursuant to Section 12(g) of the Securities Exchange Act of 1934.

Pollution Control Revenue Bonds

As of June 30, 2009, FES’, Met-Ed’s and Penelec’s currently payable long-term debt included $1.5 billion, $29 million and $45 million, respectively, 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.

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. During the second quarter of 2009, NGC remarketed the remaining $334 million of PCRBs, of which $170 million was remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. During the second quarter of 2009, FGCO remarketed approximately $248 million of PCRBs supported by LOCs set to expire in June 2009. These PCRBs were remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. Also, in June 2009, FGCO and NGC delivered FMBs to certain LOC banks listed above in connection with amendments to existing letter of credit and reimbursement agreements supporting 12 other series of PCRBs as described above and pledged FMBs to the applicable trustee under six separate series of PCRBs.

Financing Activities

The following table summarizes new debt issuances (excluding PCRB issuances and refinancings) during 2009.

Issuing Company	Issue Date	Principal (in millions)	Type	Maturity	Use of Proceeds

Met-Ed*	01/20/2009	$300	7.70% Senior Notes	2019	Repay short-term borrowings

JCP&L*	01/27/2009	$300	7.35% Senior Notes	2019	Repay short-term borrowings, fund capital expenditures and other general purposes

TE*	04/24/2009	$300	7.25% Senior Secured Notes	2020	Repay short-term borrowings, fund capital expenditures and other general purposes

Penn	06/30/2009	$100	6.09% FMB	2022	Fund capital expenditures and repurchase equity from OE

* Issuance was sold off the shelf registration statement referenced above.

109

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

FirstEnergy is 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. In preparing the financial statements, FirstEnergy and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through August 3, 2009, the date the financial statements were issued.

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 June 30, 2009 and for the three-month and six-month periods ended June 30, 2009 and 2008, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated August 3, 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

Basic earnings per share of common stock are 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 following table reconciles basic and diluted earnings per share of common stock:

	Three Months				Six Months
Reconciliation of Basic and Diluted Earnings per Share	Ended June 30				Ended June 30
of Common Stock	2009		2008		2009		2008
	(In millions, except per share amounts)
Earnings available to FirstEnergy Corp.	$	414	$	263	$	533	$	539

Average shares of common stock outstanding - Basic		304		304		304		304
Assumed exercise of dilutive stock options and awards		1		3		2		3
Average shares of common stock outstanding - Diluted		305		307		306		307

Basic earnings per share of common stock	$	1.36	$	0.86	$	1.75	$	1.77
Diluted earnings per share of common stock	$	1.36	$	0.85	$	1.75	$	1.75

110

Earnings in the second quarter of 2009 include a gain of $254 million ($0.52 per share) from the sale of FirstEnergy’s nine percent interest in the stock and output of OVEC.

3. FAIR VALUE OF FINANCIAL INSTRUMENTS

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

All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value, in the caption "short-term borrowings." The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations as of June 30, 2009 and December 31, 2008:

	June 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
FirstEnergy	$	12,389	$	12,535	$	11,585	$	11,146
FES		2,556		2,559		2,552		2,528
OE		1,169		1,233		1,232		1,223
CEI		1,723		1,806		1,741		1,618
TE		600		621		300		244
JCP&L		1,856		1,873		1,569		1,520
Met-Ed		842		858		542		519
Penelec		679		676		779		721

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

(B)	INVESTMENTS

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities.

FES and the Utilities periodically evaluate their investments for other-than-temporary impairment. They first consider their intent and ability to hold an equity investment until recovery and then consider, among other factors, the duration and the extent to which the security's fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, in accordance with FSP FAS 115-2 and FAS 124-2, FES and the Utilities consider their intent to hold the security, the likelihood that they will be required to sell the security before recovery of its cost basis, and the likelihood of recovery of the security's entire amortized cost basis.

Available-For-Sale Securities

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

The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities as of June 30, 2009 and December 31, 2008:

111

	June 30, 2009(1)								December 31, 2008(2)
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
Debt securities	(In millions)
FirstEnergy(3)	$	1,181	$	44	$	-	$	1,225	$	1,078	$	56	$	-	$	1,134
FES		476		25		-		501		401		28		-		429
OE		93		3		-		96		86		9		-		95
TE		70		3		-		73		66		8		-		74
JCP&L		249		7		-		256		249		9		-		258
Met-Ed		116		3		-		119		111		4		-		115
Penelec		178		3		-		181		164		3		-		167

Equity securities
FirstEnergy	$	512	$	76	$	-	$	588	$	589	$	39	$	-	$	628
FES		275		55		-		330		355		25		-		380
OE		15		3		-		18		17		1		-		18
JCP&L		65		4		-		69		64		2		-		66
Met-Ed		104		10		-		114		101		9		-		110
Penelec		53		4		-		57		51		2		-		53

(1) Excludes cash balances of $231 million at FirstEnergy, $209 million at FES, $14 million at JCP&L, $4 million at OE, $3 million at Penelec and $1 million at TE. (2) Excludes cash balances of $244 million at FirstEnergy, $225 million at FES, $12 million at Penelec, $4 million at OE and $1 million at Met-Ed. (3) Includes fair values as of June 30, 2009 and December 31, 2008 of $982 million and $953 million of government obligations, $238 million and $175 million of corporate debt and $5 million and $6 million of mortgage backed securities.

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income as of June 30, 2009 were as follows:

	FirstEnergy		FES		OE		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Proceeds from sales	$	1,001	$	537	$	25	$	77	$	245	$	63	$	54
Realized gains		30		24		-		3		3		1		-
Realized losses		91		58		3		-		11		12		7
Interest and dividend income		30		14		2		1		7		3		3

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

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

Held-To-Maturity Securities

The following table provides the amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities except for investments of $271 million and $293 million excluded by SFAS 107 as of June 30, 2009 and December 31, 2008:

	June 30, 2009								December 31, 2008
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
Debt securities	(In millions)
FirstEnergy	$	627	$	51	$	-	$	678	$	673	$	14	$	13	$	674
OE		230		9		-		239		240		-		13		227
CEI		389		43		-		432		426		9		-		435

112

The following table provides the approximate fair value and related carrying amounts of notes receivable as of June 30, 2009 and December 31, 2008:

	June 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Notes receivable	(In millions)
FirstEnergy	$	40	$	38	$	45	$	44
FES		6		6		75		74
OE		193		233		257		294
TE		161		184		180		189

The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. The maturity dates range from 2009 to 2040.

(C)	RECURRING FAIR VALUE MEASUREMENTS

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 on Form 10-K for the year ended December 31, 2008.

The following tables set forth financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of June 30, 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 June 30, 2009
		Level 1 - Assets (In millions)								Level 1 - Liabilities
		Derivatives		Available-for-Sale Securities(1)		Other Investments		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	1	$	495	$	-	$	496	$	19	$	-	$	19
FES		1		237		-		238		19		-		19
OE		-		18		-		18		-		-		-
JCP&L		-		70		-		70		-		-		-
Met-Ed		-		109		-		109		-		-		-
Penelec		-		61		-		61		-		-		-

		Level 2 - Assets								Level 2 - Liabilities
		Derivatives		Available-for-Sale Securities(1)		Other Investments		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	41	$	1,547	$	84	$	1,672	$	19	$	-	$	19
FES		21		800		-		821		15		-		15
OE		-		98		-		98		-		-		-
TE		-		73		-		73		-		-		-
JCP&L		5		270		-		275		-		-		-
Met-Ed		9		126		-		135		-		-		-
Penelec		5		179		-		184		-		-		-

		Level 3 - Assets								Level 3 - Liabilities
		Derivatives		Available-for-Sale Securities(1)		NUG Contracts(2)		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	-	$	-	$	214	$	214	$	-	$	750	$	750
JCP&L		-		-		9		9		-		475		475
Met-Ed		-		-		184		184		-		161		161
Penelec		-		-		21		21		-		114		114

(1)

Consists of investments in the nuclear decommissioning trusts, the spent nuclear fuel trusts and the NUG trusts. Balance

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

(2) NUG contracts are completely offset by regulatory assets and do not impact earnings.

113

Recurring Fair Value Measures as of December 31, 2008
		Level 1 – Assets (In millions)								Level 1 - Liabilities
		Derivatives		Available-for-Sale Securities(1)		Other Investments		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	-	$	537	$	-	$	537	$	25	$	-	$	25
FES		-		290		-		290		25		-		25
OE		-		18		-		18		-		-		-
JCP&L		-		67		-		67		-		-		-
Met-Ed		-		104		-		104		-		-		-
Penelec		-		58		-		58		-		-		-

		Level 2 - Assets								Level 2 - Liabilities
		Derivatives		Available-for-Sale Securities(1)		Other Investments		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	40	$	1,464	$	83	$	1,587	$	31	$	-	$	31
FES		12		744		-		756		28		-		28
OE		-		98		-		98		-		-		-
TE		-		73		-		73		-		-		-
JCP&L		7		255		-		262		-		-		-
Met-Ed		14		121		-		135		-		-		-
Penelec		7		174		-		181		-		-		-

		Level 3 - Assets								Level 3 - Liabilities
		Derivatives		Available-for-Sale Securities(1)		NUG Contracts(2)		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	-	$	-	$	434	$	434	$	-	$	766	$	766
JCP&L		-		-		14		14		-		532		532
Met-Ed		-		-		300		300		-		150		150
Penelec		-		-		120		120		-		84		84

(1)

Consists of investments in the 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 and do not impact earnings.

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

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, 2009 and 2008 (in millions):

	FirstEnergy			JCP&L			Met-Ed			Penelec
Balance as of January 1, 2009	$	(332	)	$	(518	)	$	150		$	36
Settlements(1)		179			90			43			47
Unrealized gains (losses)(1)		(383	)		(38	)		(170	)		(176	)
Net transfers to (from) Level 3		-			-			-			-
Balance as of June 30, 2009	$	(536	)	$	(466	)	$	23		$	(93	)

Change in unrealized gains (losses) relating to instruments held as of June 30, 2009	$	(383	)	$	(38	)	$	(170	)	$	(176	)

Balance as of April 1, 2009	$	(476	)	$	(518	)	$	76		$	(34	)
Settlements(1)		96			44			26			27
Unrealized gains (losses)(1)		(156	)		8			(79	)		(86	)
Net transfers to (from) Level 3		-			-			-			-
Balance as of June 30, 2009	$	(536	)	$	(466	)	$	23		$	(93	)

Change in unrealized gains (losses) relating to instruments held as of June 30, 2009	$	(156	)	$	8		$	(79	)	$	(86	)

114

	FirstEnergy			JCP&L			Met-Ed			Penelec
Balance as of January 1, 2008	$	(803	)	$	(750	)	$	(28	)	$	(25	)
Settlements(1)		110			95			2			13
Unrealized gains (losses)(1)		676			11			376			290
Net transfers to (from) Level 3		-			-			-			-
Balance as of June 30, 2008	$	(17	)	$	(644	)	$	350		$	278

Change in unrealized gains (losses) relating to instruments held as of June 30, 2008	$	676		$	11		$	376		$	290

Balance as of April 1, 2008	$	(419	)	$	(682	)	$	145		$	119
Settlements(1)		46			45			(3	)		5
Unrealized gains (losses)(1)		356			(7	)		208			154
Net transfers to (from) Level 3		-			-			-			-
Balance as of June 30, 2008	$	(17	)	$	(644	)	$	350		$	278

Change in unrealized gains (losses) relating to instruments held as of June 30, 2008	$	356		$	(7	)	$	208		$	154

(1) Changes in 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 Sheets 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 $300 million to hedge against changes in associated interest rates. Hedges with a notional value of $100 million expire in November 2009 and $100 million expire in November 2010. The swaps are accounted for as cash flow hedges under SFAS 133. As of June 30, 2009, the fair value of outstanding swaps was $(3) 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 six months 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.

As of June 30, 2009 and December 31, 2008, the fair value of outstanding interest rate derivatives was $(3) million. Interest rate derivatives are included in "Other Noncurrent Liabilities" on FirstEnergy’s consolidated balance sheets. The effect of interest rate derivatives on the consolidated statements of income and comprehensive income during the three months and six months ended June 30, 2009 and 2008 were:

115

		Three Months						Six Months
		Ended June 30						Ended June 30
		2009			2008			2009			2008
		(In millions)
Effective Portion
	Gain Recognized in AOCL	$	2		$	-		$	-		$	-
	Loss Reclassified from AOCL into Interest Expense		(6	)		(3	)		(11	)		(7	)
Ineffective Portion
	Loss Recognized in Interest Expense		-			(4	)		-			(5	)

Total unamortized losses included in AOCL associated with prior interest rate hedges totaled $113 million ($68 million net of tax) as of June 30, 2009. Based on current estimates, approximately $9 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
			June 30,		December 31,					June 30,		December 31,
			2009		2008					2009		2008
Cash Flow Hedges			(In millions)			Cash Flow Hedges				(In millions)
Electricity Forwards						Electricity Forwards
	Current Assets	$	21	$	11		Current Liabilities		$	15	$	27
Natural Gas Futures						Natural Gas Futures
	Current Assets		-		-		Current Liabilities			9		4
	Long-Term Deferred Charges		-		-		Noncurrent Liabilities			3		5
Other						Other
	Current Assets		-		-			Current Liabilities		7		12
	Long-Term Deferred Charges		-		-			Noncurrent Liabilities		4		4
		$	21	$	11				$	38	$	52


Derivative Assets						Derivative Liabilities
			Fair Value							Fair Value
			June 30, 2009		December 31, 2008					June 30, 2009		December 31, 2008
Economic Hedges			(In millions)			Economic Hedges				(In millions)
NUG Contracts						NUG Contracts
	Power Purchase							Power Purchase
	Contract Asset	$	214	$	434			Contract Liability	$	750	$	766
Other						Other
	Current Assets		2		1			Current Liabilities		-		1
	Long-Term Deferred Charges		19		28			Noncurrent Liabilities		-		-
		$	235	$	463				$	750	$	767
Total Commodity Derivatives		$	256	$	474	Total Commodity Derivatives			$	788	$	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 June 30, 2009.

116

	Purchases		Sales			Net			Units
	(In thousands)
Electricity Forwards		471		(3,735	)		(3,264	)	MWH
Heating Oil Futures		13,188		(1,260	)		11,928		Gallons
Natural Gas Futures		3,850		-			3,850		mmBtu

The effect of derivative instruments on the consolidated statements of income and comprehensive income for the three and six months ended June 30, 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
Three Months Ended June 30, 2009			(in millions)
Gain (Loss) Recognized in AOCL (Effective Portion)		$	6		$	-		$	2		$	8
Effective Gain (Loss) Reclassified to:(1)
	Purchased Power Expense		1			-			-			1
	Fuel Expense		-			(4	)		(4	)		(8	)

Six Months Ended June 30, 2009
Gain (Loss) Recognized in AOCL (Effective Portion)		$	4		$	(7	)	$	1		$	(2	)
Effective Gain (Loss) Reclassified to:(1)
	Purchased Power Expense		(17	)		-			-			(17	)
	Fuel Expense		-			(4	)		(8	)		(12	)


Three Months Ended June 30, 2008
Gain (Loss) Recognized in AOCL (Effective Portion)		$	(16	)	$	3		$	-		$	(13	)
Effective Gain (Loss) Reclassified to:(1)
	Purchased Power Expense		4			-			-			4
	Fuel Expense		-			1			-			1

Six Months Ended June 30, 2008
Gain (Loss) Recognized in AOCL (Effective Portion)		$	(30	)	$	6		$	-		$	(24	)
Effective Gain (Loss) Reclassified to:(1)
	Purchased Power Expense		(13	)		-			-			(13	)
	Fuel Expense		-			1			-			1

(1) The ineffective portion was immaterial.

		Three Months Ended June 30									Six Months Ended June 30
Derivatives Not in Hedging Relationships			NUG									NUG
			Contracts			Other			Total			Contracts			Other			Total
2009		(In millions)
Unrealized Gain (Loss) Recognized in:
Fuel Expense(1)		$	-		$	2		$	2		$	-		$	2		$	2
Regulatory Assets(2)			(156	)		-			(156	)		(383	)		-			(383	)
		$	(156	)	$	2		$	(154	)	$	(383	)	$	2		$	(381	)
Realized Gain (Loss) Reclassified to:
Fuel Expense(1)		$	-		$	-		$	-		$	-		$	(1	)	$	(1	)
Regulatory Assets(2)			(96	)		-			(96	)		(179	)		10			(169	)
		$	(96	)	$	-		$	(96	)	$	(179	)	$	9		$	(170	)
2008
Unrealized Gain (Loss) Recognized in:
Regulatory Assets(2)		$	356		$	-		$	356		$	676		$	-		$	676

Realized Gain (Loss) Reclassified to:
Regulatory Assets(2)		$	(46	)	$	(1	)	$	(47	)	$	(110	)	$	10		$	(100	)

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

Total unamortized losses included in AOCL associated with commodity derivatives were $17 million ($10 million net of tax) as of June 30, 2009, as compared to $44 million ($27 million net of tax) as of December 31, 2008. The net of tax change resulted from a net $1 million decrease related to current hedging activity and a $16 million decrease due to net hedge losses reclassified to earnings during the first six months of 2009. Based on current estimates, approximately $6 million (after tax) of the net deferred losses on derivative instruments in AOCL as of June 30, 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.

117

Many of FirstEnergy’s commodity derivatives contain credit risk features. As of June 30, 2009, FirstEnergy posted $133 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 June 30, 2009 was $1 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 $19 million of additional collateral related to commodity derivatives.

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.

On June 2, 2009, FirstEnergy amended its health care benefits plan (Plan) for all employees and retirees eligible to participate in the Plan. The Plan amendment, which reduces future health care coverage subsidies paid by FirstEnergy on behalf of participants, triggered a remeasurement of FirstEnergy’s other postretirement benefit plans as of May 31, 2009. As a result of the remeasurement, the Plan’s discount rate was revised to 7.5% while the expected long-term rate of return on assets remained at 9%. The remeasurement and Plan amendment increased FirstEnergy’s accumulated other comprehensive income by $449 million in the second quarter of 2009 and will reduce FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the remainder of 2009 by $48 million, including a $7 million reduction that is applicable to the second quarter of 2009.

FirstEnergy’s net pension and OPEB expenses (benefits) for the three months ended June 30, 2009 and 2008 were $38 million and $(15) million, respectively. For the six months ended June 30, 2009 and 2008, FirstEnergy’s net pension and OPEB expenses (benefits) were $80 million and $(29) million, respectively. The components of FirstEnergy's net pension and other postretirement benefit costs (including amounts capitalized) for the three months and six months ended June 30, 2009 and 2008, consisted of the following:

	Three Months						Six Months
	Ended June 30						Ended June 30
Pension Benefits	2009			2008			2009			2008
	(In millions)
Service cost	$	22		$	22		$	43		$	43
Interest cost		80			75			159			150
Expected return on plan assets		(81	)		(116	)		(162	)		(231	)
Amortization of prior service cost		3			3			7			6
Recognized net actuarial loss		42			2			85			4
Net periodic cost (credit)	$	66		$	(14	)	$	132		$	(28	)

	Three Months						Six Months
	Ended June 30						Ended June 30
Other Postretirement Benefits	2009			2008			2009			2008
	(In millions)
Service cost	$	4		$	5		$	8		$	9
Interest cost		18			18			38			37
Expected return on plan assets		(9	)		(13	)		(18	)		(26	)
Amortization of prior service cost		(41	)		(37	)		(79	)		(74	)
Recognized net actuarial loss		15			12			31			24
Net periodic cost (credit)	$	(13	)	$	(15	)	$	(20	)	$	(30	)

118

Pension and postretirement benefit obligations are allocated to FirstEnergy's subsidiaries employing the plan participants. FES and the Utilities 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 Utilities for the three months and six months ended June 30, 2009 and 2008 were as follows:

	Three Months					Six Months
	Ended June 30					Ended June 30
Pension Benefit Cost (Credit)	2009		2008			2009		2008
	(In millions)
FES	$	18	$	5		$	36	$	11
OE		7		(6	)		14		(12	)
CEI		5		(1	)		10		(2	)
TE		2		(1	)		3		(1	)
JCP&L		9		(3	)		18		(7	)
Met-Ed		6		(2	)		11		(5	)
Penelec		4		(3	)		9		(6	)
Other FirstEnergy subsidiaries		15		(3	)		31		(6	)
	$	66	$	(14	)	$	132	$	(28	)

	Three Months						Six Months
	Ended June 30						Ended June 30
Other Postretirement Benefit Cost (Credit)	2009			2008			2009			2008
	(In millions)
FES	$	(3	)	$	(2	)	$	(4	)	$	(4	)
OE		(3	)		(2	)		(5	)		(3	)
CEI		-			1			1			1
TE		-			1			1			2
JCP&L		(1	)		(4	)		(2	)		(8	)
Met-Ed		(1	)		(3	)		(2	)		(5	)
Penelec		(1	)		(3	)		(2	)		(6	)
Other FirstEnergy subsidiaries		(4	)		(3	)		(7	)		(7	)
	$	(13	)	$	(15	)	$	(20	)	$	(30	)

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 distribution to owners.

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 to affiliates of the Boich Companies to purchase an additional 5% economic interest in the Signal Peak mining and coal transportation operations. Voting interests remained unchanged after the sale was 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 joint venture in its financial statements.

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.

119

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	$	1,347	$	1,172	$	175
OE	749		549		200
CEI	703		74		629
TE	703		376		327

(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.

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 Utilities 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 25 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.

120

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. As of June 30, 2009, the net above-market loss liability projected for these eight NUG agreements was $9 million. Purchased power costs from these entities during the three months ended June 30, 2009 and 2008 are shown in the following table:

	Three Months				Six Months
	Ended June 30				Ended June 30
	2009		2008		2009		2008
	(In millions)
JCP&L	$	18	$	22	$	37	$	41
Met-Ed		13		16		28		32
Penelec		8		8		17		17
Total	$	39	$	46	$	82	$	90

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, 2009, $356 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 its 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 second quarter of 2009 and the first six months of 2008, there were no material changes to FirstEnergy's unrecognized tax benefits. As of June 30, 2009, FirstEnergy expects that it is reasonably possible that $195 million of 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.

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 June 30, 2009 was $64 million, as compared to $59 million as of December 31, 2008. During the first six months of 2009 and 2008, there were no material changes to the amount of interest accrued.

In 2008, FirstEnergy, on behalf of FGCO and NGC, filed a change in accounting method related to the costs to repair and maintain electric generation stations. During the second quarter of 2009, the IRS approved the change in accounting method and FGCO and NGC are in the process of computing the amount of costs that will qualify as a deduction. If the IRS completes its review process by the extended filing date of September 15, 2009, an amount for the repair deduction will be included in FirstEnergy’s 2008 consolidated tax return. This change in accounting method could have a significant impact on taxable income for 2008 and could reduce the amount of taxes to be accrued in the third quarter of 2009, with no corresponding impact to the effective tax rate for the quarter.

121

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 June 30, 2009, outstanding guarantees and other assurances aggregated approximately $4.6 billion, consisting primarily of parental guarantees - $1.3 billion, subsidiaries’ guarantees - $2.6 billion, surety bonds - $0.1 billion and LOCs - $0.5 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 $1.3 billion discussed above) as of June 30, 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 June 30, 2009, FirstEnergy's maximum exposure under these collateral provisions was $601 million, consisting of $41 million due to “material adverse event” contractual clauses and $560 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 $700 million, consisting of $49 million due to “material adverse event” contractual clauses and $651 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 $108 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 June 30, 2009, and forward prices as of that date, FES had $179 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 $73 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post significantly higher amounts for margining.

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 irrevocably 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.

122

(B)

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.

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 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.

123

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. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allege 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 seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. 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 and Connecticut’s 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 1, 2009, the Court held oral argument on Met-Ed’s motion to dismiss the complaint.

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.

124

National Ambient Air Quality Standards

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 any future regulations 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

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 House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. 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.

125

Clean Water Act

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.

Regulation of Waste Disposal

126

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. 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 due to the outages.

Nuclear Plant Matters

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 June 8, 2009, the NRC issued the final Safety Evaluation Report (SER) supporting the renewed license for Beaver Valley Units 1 and 2. On July 8, 2009, the NRC’s Advisory Committee on Reactor Safeguards (ACRS) held a public meeting to consider the NRC’s final SER. Much of the ACRS’ discussion involved questions raised by a letter from Citizens Power regarding the extent of corrective actions for the 2009 discovery of a penetration in the Beaver Valley Unit 1 containment liner. On July 28, 2009, FENOC submitted to the NRC further clarifications on the supplemental volumetric examinations of Beaver Valley’s containment liners. FENOC anticipates another meeting with the ACRS regarding the container liner during September 2009. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and is scheduled 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.

127

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.

128

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.

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.

On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. ReliabilityFirst issued an Initial Notice of Alleged Violation on June 22, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-report of violation.

(B) OHIO

129

130

SB221 also requires electric distribution utilities to implement energy efficiency programs that achieve a total annual 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 1%, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. Additionally, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they serve in 2009. FirstEnergy has efforts underway to address compliance with these requirements. Costs associated with compliance are recoverable from customers.

·	power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a prudent 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;

131

·	utilities must reduce peak demand by a minimum of 4.5% by May 31, 2013;

·	utilities must reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and

·	the definition of Alternative Energy was expanded to include additional types of hydroelectric and biomass facilities.

(D) NEW JERSEY

132

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.

(E) FERC MATTERS

Transmission Service between MISO and PJM

PJM Transmission Rate

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. AEP's 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.

133

Post Transition Period Rate Design

~~Distribution of MISO Network Service Revenues~~

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

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

On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was 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~~U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its affiliated operating utility companies, filed a ~~filing~~motion to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. This matter is currently pending before the FERC.intervene on March 10, 2009.

~~MISO Ancillary Services Market and Balancing Area Consolidation~~Changes ordered for PJM Reliability Pricing Model (RPM) Auction

~~MISO made~~On May 30, 2008, a ~~filing on September 14, 2007~~group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred 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~~collectively as the ~~NERC registered balancing authority for~~RPM Buyers) filed a complaint at the ~~region. This filing would permit load serving entities to purchase their operating reserve requirements in a competitive market. FirstEnergy supports~~FERC against PJM alleging that three of the ~~proposal to establish markets for Ancillary Services~~four transitional RPM auctions yielded prices that are unjust and ~~consolidate existing balancing areas.~~unreasonable under the Federal Power Act. On ~~February 25,~~September 19, 2008, the FERC denied the RPM Buyers’ complaint. 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 ~~approving~~terminating settlement discussions. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the ~~ASM subject to certain compliance filings. MISO has since notified the FERC~~PJM December 12, 2008 filing as its starting point, and stated that ~~the start of its ASM is delayed until September of 2008.~~unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.

41134

~~Duquesne’s Request~~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 ~~Withdraw from~~RPM; however, the basic construct of RPM remains intact. On April 3, 2009, PJM

~~On November 8, 2007, Duquesne Light Company (Duquesne)~~ filed ~~a request~~ with the FERC ~~to exit PJM and to join the MISO. In its filing, Duquesne asked the FERC to be relieved of~~requesting clarification on 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~~the March 26, 2009 Order. On April 27, 2009, PJM ~~without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address~~submitted a compliance filing addressing the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.

On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne to pay the PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FirstEnergy and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather,changes the FERC ordered ~~Duquesne to make a compliance filing~~ in ~~forty-five days detailing how Duquesne will satisfy its obligations under~~ the ~~PJM Transmission Owners’ Agreement. The FERC likewise directed~~March 26, 2009 Order; and subsequently, numerous parties filed requests for rehearing of the ~~MISO to submit detailed plans to integrate Duquesne into the MISO. Finally,~~March 26, 2009 Order. On June 18, 2009, the FERC ~~directed MISO~~denied rehearing and ~~PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into the MISO. These issues remain unresolved. If Duquesne satisfies all~~request for oral argument of the ~~obligations set by the FERC, its planned transition date is October 9, 2008.~~March 26 Order.

~~On March 18, 2008,~~PJM has reconvened 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 changeCapacity Market Evolution Committee to ~~“External Resource” upon Duquesne’s exit from PJM, these generators can contract with PJM for the transmission reservations necessary to participate~~address issues not addressed in the ~~May 2008 auction. FirstEnergy has complied with FERC’s order by obtaining executed transmission service agreements~~February 2009 settlement in preparation for ~~firm point-to-point transmission service for the 2011-2012 delivery year~~September 1, 2009 and ~~as such, FirstEnergy satisfies the criteria~~December 1, 2009 compliance filings that will recommend more incremental improvements to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. FirstEnergy is participating in the May 2008 RPM auction for the 2011-2012 RPM delivery year.its RPM.

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 iswas proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for ~~load serving~~load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for ~~load serving~~load-serving entities in its state. FirstEnergy ~~generally supports~~believes the proposal ~~as it~~ promotes a mechanism that will result in ~~long-term~~ commitments from both load-serving entities and resources, including both generation and demand side resources, that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were ~~filed~~submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, ~~2008.~~2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. AOn 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 ~~is due on or before June 25, 2008.~~

~~Organized Wholesale Power Markets~~which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.

On ~~February 21,~~October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a ~~NOPR through which~~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 was implemented as planned on June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it ~~proposes~~ to ~~adopt new rules~~address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it ~~states will “improve operations~~believes the FERC should address and clarify.

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 a December 23, 2008 waiver of restrictions on affiliate sales without prior approval of the FERC.

On May 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate in ~~organized electric markets, boost competition~~the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES was the successful bidder for 51 tranches, and ~~bring~~subsequently purchased 11 additional ~~benefits to consumers.”~~tranches from other bidders. The ~~proposed rule addresses demand response~~auction resulted in an overall weighted average wholesale price of 6.15 cents per KWH for generation and ~~market pricing during reserve shortages, long-term power contracting, market-monitoring policies,~~transmission. The new prices for PLR service went into effect with usage beginning June 1, 2009, and responsiveness of RTOs and ISOs to stakeholders and customers. FirstEnergy does not believe that the proposed rule will have a significant impact on its operations. Comments on the NOPR were filed on April 18, 2008.continuing through May 31, 2011.

42135

~~12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS~~

10. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

~~SFAS 141(R)~~FSP FAS 132 (R)-1 – ~~“Business Combinations”~~“Employers’ Disclosures about Postretirement Benefit Plan Assets”

In December ~~2007,~~2008, the FASB issued Staff Position FAS 132(R)-1, which provides guidance on an employer’s disclosures about 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.

SFAS 166 – “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140”

In June 2009, the FASB issued SFAS ~~141(R),~~166, which amends the derecognition guidance in SFAS 140 and eliminates the concept of a qualifying special-purpose entity (QSPE). It removes the exception from applying FIN 46R to QSPEs and requires an evaluation of all existing QSPEs to determine whether they must be consolidated in accordance with SFAS 167. This Statement is effective for financial asset transfers that occur in fiscal years beginning after November 15, 2009. FirstEnergy does not expect this Standard to have a material effect upon its financial statements.

SFAS 167 – “Amendments to FASB Interpretation No. 46(R)”

In June 2009, the ~~acquiring~~FASB issued SFAS 167, which amends the consolidation guidance applied to VIEs. This Statement replaces the quantitative approach previously required to determine which entity has a controlling financial interest in a ~~business combination~~VIE with a qualitative approach. Under the new approach, the primary beneficiary of a VIE is the entity that has both (a) the power to ~~recognize all~~direct the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users allactivities of the ~~information they need~~VIE that most significantly impact the entity’s economic performance, and (b) the obligation to ~~evaluate and understand the nature and financial effect~~absorb losses of the ~~business combination.~~entity, or the right to receive benefits from the entity, that could be significant to the VIE. SFAS ~~141(R) attempts to reduce~~167 also requires ongoing reassessments of whether an entity is the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that were established as partprimary beneficiary of a ~~business combination prior to the implementation of this Standard.~~VIE and enhanced disclosures about an entity’s involvement in VIEs. This Statement is effective for fiscal years beginning after November 15, 2009. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

SFAS ~~160 - “Noncontrolling Interests in Consolidated Financial Statements~~168 – ~~an Amendment~~“The FASB Accounting Standards CodificationTM and the Hierarchy of ~~ARB~~Generally Accepted Accounting Principles – a replacement of FASB Statement No. ~~51”~~162”

In ~~December 2007,~~June 2009, the FASB issued SFAS ~~160~~168, which recognizes the FASB Accounting Standards CodificationTM (Codification) as the source of authoritative GAAP. It also recognizes that ~~establishes~~rules and interpretative releases of the SEC under federal securities laws are sources of authoritative GAAP for SEC registrants. The Codification supersedes all non-SEC 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.standards. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FirstEnergy’s financial statements.

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

~~In March 2008, the FASB issued SFAS 161, which requires~~ ~~enhancements to~~ the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This disclosure is intended to better convey the purpose of derivatives use in terms of the risks that the entity is intending to manage. The FASB believes disclosing the fair values of derivative instruments and their gains and losses in a tabular format is designed to provide a more complete picture of the location in an entity’s financial statements ~~of both the derivative positions existing at period end~~issued for interim and ~~the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide~~annual periods ending after September 15, 2009. This Statement will change how FirstEnergy references GAAP in its financial statement users information on the potential effect on an entity’s liquidity from using derivatives. Finally, this Statement requires cross-referencing within the footnotes, which is intended to help users of financial statements locate important information about derivative instruments. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.disclosures.

~~13.~~

136

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~~"reportable operating segments.”" FES and the Utilities do not have separate 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~~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 Met-Ed's and Penelec's partial requirements purchased power agreements and from non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.

The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive ~~electric~~electricity sales primarily in Ohio, Pennsylvania, Maryland and Michigan, owns or leases and operates ~~FirstEnergy’s~~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~~segment's customers. The ~~segment’s~~segment's internal revenues represent ~~the affiliated company PSA sales.~~

sales to its affiliates in Ohio and Pennsylvania.

The Ohio transitional generation services segment represents the ~~regulated~~ generation commodity operations of ~~FirstEnergy’s~~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~~segment's total assets consist primarily of accounts receivable for generation revenues from retail customers.

Segment Financial Information
Ohio
Energy Competitive Transitional
Delivery Energy Generation Reconciling
Three Months Ended Services Services Services Other Adjustments Consolidated
(In millions)
March 31, 2008
External revenues $ 2,212 $ 329 $ 707 $ 40 $ (11 ) $ 3,277
Internal revenues - 776 - - (776 ) -
Total revenues 2,212 1,105 707 40 (787 ) 3,277
Depreciation and amortization 255 53 4 - 5 317
Investment income 45 (6 ) 1 - (23 ) 17
Net interest charges 103 27 - - 41 171
Income taxes 119 58 15 14 (19 ) 187
Net income 179 87 23 22 (35 ) 276
Total assets 23,211 8,108 257 281 558 32,415
Total goodwill 5,582 24 - - - 5,606
Property additions 255 462 - 12 (18 ) 711

March 31, 2007
External revenues $ 2,040 $ 321 $ 619 $ 12 $ (19 ) $ 2,973
Internal revenues - 714 - - (714 ) -
Total revenues 2,040 1,035 619 12 (733 ) 2,973
Depreciation and amortization 220 51 (15 ) 1 6 263
Investment income 70 3 1 - (41 ) 33
Net interest charges 107 49 1 2 21 180
Income taxes 148 65 15 5 (33 ) 200
Net income 218 98 24 1 (51 ) 290
Total assets 23,526 7,089 246 254 675 31,790
Total goodwill 5,874 24 - - - 5,898
Property additions 155 124 - 1 16 296
137

Segment Financial Information
						Ohio
	Energy		Competitive			Transitional
	Delivery		Energy			Generation						Reconciling
Three Months Ended	Services		Services			Services			Other			Adjustments			Consolidated
	(In millions)
June 30, 2009
External revenues	$	1,924	$	504		$	868		$	5		$	(30	)	$	3,271
Internal revenues		-		839			-			-			(839	)		-
Total revenues		1,924		1,343			868			5			(869	)		3,271
Depreciation and amortization		294		68			4			3			4			373
Investment income		35		6			-			-		��	(14	)		27
Net interest charges		113		18			-			2			40			173
Income taxes		89		185			14			(20	)		(20	)		248
Net income		133		276			21			18			(40	)		408
Total assets		22,849		10,144			366			684			263			34,306
Total goodwill		5,551		24			-			-			-			5,575
Property additions		178		248			-			70			(7	)		489

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

Six Months Ended

June 30, 2009
External revenues	$	4,033	$	839		$	1,780		$	12		$	(59	)	$	6,605
Internal revenues		-		1,732			-			-			(1,732	)		-
Total revenues		4,033		2,571			1,780			12			(1,791	)		6,605
Depreciation and amortization		766		132			(41	)		4			7			868
Investment income		64		(23	)		1			-			(26	)		16
Net interest charges		223		36			-			3			77			339
Income taxes		61		288			30			(37	)		(40	)		302
Net income		91		431			45			35			(79	)		523
Total assets		22,849		10,144			366			684			263			34,306
Total goodwill		5,551		24			-			-			-			5,575
Property additions		343		669			-			119			12			1,143

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			43			48			(76	)		540
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

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.

138

~~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, unconditionally and irrevocably guaranteed all of ~~FGCO’s~~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~~trust's undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including ~~FES’~~FES' lease guaranty. This transaction is classified as an operating lease under GAAP for FES and FirstEnergy and as a financing for FGCO.

The condensed consolidating statements of income for the ~~three months~~three-month and six-month periods ended ~~March 31,~~June 30, 2009 and 2008, ~~and 2007,~~ consolidating balance sheets as of ~~March~~June 30, 2009 and December 31, 2008 and ~~December 31, 2007 and condensed~~ consolidating statements of cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 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’~~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.

44139

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended June 30, 2009	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)

REVENUES	$	1,067,987		$	703,110		$	389,695		$	(819,640	)	$	1,341,152

EXPENSES:
Fuel		5,027			238,832			26,450			-			270,309
Purchased power from non-affiliates		185,613			-			-			-			185,613
Purchased power from affiliates		814,622			5,018			51,249			(819,640	)		51,249
Other operating expenses		35,771			99,145			131,159			12,189			278,264
Provision for depreciation		1,017			30,191			35,654			(1,314	)		65,548
General taxes		3,769			11,332			6,184			-			21,285
Total expenses		1,045,819			384,518			250,696			(808,765	)		872,268

OPERATING INCOME		22,168			318,592			138,999			(10,875	)		468,884

OTHER INCOME (EXPENSE):
Miscellaneous income, including net income
from equity investees		288,794			951			6,030			(282,510	)		13,265
Interest expense - affiliates		(34	)		(1,623	)		(1,658	)		-			(3,315	)
Interest expense - other		(2,900	)		(24,967	)		(14,677	)		16,273			(26,271	)
Capitalized interest		46			11,126			2,856			-			14,028
Total other income (expense)		285,906			(14,513	)		(7,449	)		(266,237	)		(2,293	)

INCOME BEFORE INCOME TAXES		308,074			304,079			131,550			(277,112	)		466,591

INCOME TAXES		10,672			108,114			48,163			2,240			169,189

NET INCOME	$	297,402		$	195,965		$	83,387		$	(279,352	)	$	297,402

140

FIRSTENERGY SOLUTIONS CORP.

CONDENSED 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

141

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Six Months Ended June 30, 2009	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)

REVENUES	$	2,269,882		$	1,249,036		$	785,323		$	(1,736,983	)	$	2,567,258

EXPENSES:
Fuel		7,122			513,679			55,666			-			576,467
Purchased power from non-affiliates		345,955			-			-			-			345,955
Purchased power from affiliates		1,729,883			7,100			114,456			(1,736,983	)		114,456
Other operating expenses		74,038			203,588			283,615			24,379			585,620
Provision for depreciation		2,036			60,211			67,303			(2,629	)		126,921
General taxes		8,475			23,958			12,228			-			44,661
Total expenses		2,167,509			808,536			533,268			(1,715,233	)		1,794,080

OPERATING INCOME		102,373			440,500			252,055			(21,750	)		773,178

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		409,307			904			(23,607	)		(399,702	)		(13,098	)
Interest expense - affiliates		(68	)		(3,381	)		(2,845	)		-			(6,294	)
Interest expense - other		(5,420	)		(46,025	)		(29,845	)		32,492			(48,798	)
Capitalized interest		97			18,876			5,133			-			24,106
Total other income (expense)		403,916			(29,626	)		(51,164	)		(367,210	)		(44,084	)

INCOME BEFORE INCOME TAXES		506,289			410,874			200,891			(388,960	)		729,094

INCOME TAXES		38,206			147,256			71,092			4,457			261,011

NET INCOME	$	468,083		$	263,618		$	129,799		$	(393,417	)	$	468,083

142

FIRSTENERGY SOLUTIONS CORP.

CONDENSED 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

143

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of June 30, 2009	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	120,000	$	34	$	-	$	-		$	120,034
Receivables-
Customers		75,753		-		-		-			75,753
Associated companies		222,514		152,509		105,559		(265,220	)		215,362
Other		3,477		10,979		4,853		-			19,309
Notes receivable from associated companies		369,068		1,277		-		-			370,345
Materials and supplies, at average cost		10,370		329,132		210,710		-			550,212
Prepayments and other		76,784		18,875		2,722		-			98,381
		877,966		512,806		323,844		(265,220	)		1,449,396

PROPERTY, PLANT AND EQUIPMENT:
In service		89,296		5,501,668		5,025,760		(389,939	)		10,226,785
Less - Accumulated provision for depreciation		11,838		2,760,063		1,801,089		(172,808	)		4,400,182
		77,458		2,741,605		3,224,671		(217,131	)		5,826,603
Construction work in progress		3,832		1,735,258		280,658		-			2,019,748
		81,290		4,476,863		3,505,329		(217,131	)		7,846,351

INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,040,410		-			1,040,410
Investment in associated companies		4,059,946		-		-		(4,059,946	)		-
Other		1,517		27,493		202		-			29,212
		4,061,463		27,493		1,040,612		(4,059,946	)		1,069,622
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		7,250		424,814		-		(280,607	)		151,457
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		-		17,533		-		56,748			74,281
Other		40,108		67,288		8,782		(53,873	)		62,305
		71,606		608,485		31,392		(277,732	)		433,751
	$	5,092,325	$	5,625,647	$	4,901,177	$	(4,820,029	)	$	10,799,120

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	717	$	698,493	$	951,240	$	(18,186	)	$	1,632,264
Short-term borrowings-
Associated companies		-		174,769		135,063		-			309,832
Other		1,100,000		-		-		-			1,100,000
Accounts payable-
Associated companies		288,626		184,839		131,438		(237,508	)		367,395
Other		55,039		113,446		-		-			168,485
Accrued taxes		56,092		33,217		22,274		(42,824	)		68,759
Other		38,397		97,054		10,824		34,715			180,990
		1,538,871		1,301,818		1,250,839		(263,803	)		3,827,725

CAPITALIZATION:
Common stockholder's equity		3,494,790		2,136,867		1,905,900		(4,042,767	)		3,494,790
Long-term debt and other long-term obligations		21,620		1,688,863		533,990		(1,278,796	)		965,677
		3,516,410		3,825,730		2,439,890		(5,321,563	)		4,460,467

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,009,727			1,009,727
Accumulated deferred income taxes		-		-		244,390		(244,390	)		-
Accumulated deferred investment tax credits		-		37,899		22,663		-			60,562
Asset retirement obligations		-		24,627		866,878		-			891,505
Retirement benefits		18,841		113,041		-		-			131,882
Property taxes		-		27,494		22,610		-			50,104
Lease market valuation liability		-		284,952		-		-			284,952
Other		18,203		10,086		53,907		-			82,196
		37,044		498,099		1,210,448		765,337			2,510,928
	$	5,092,325	$	5,625,647	$	4,901,177	$	(4,820,029	)	$	10,799,120

144

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)

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

145

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Six Months Ended June 30, 2009	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)

NET CASH PROVIDED FROM OPERATING ACTIVITIES	$	285,284		$	314,041		$	221,625		$	(8,734	)	$	812,216

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			347,710			333,965			-			681,675
Short-term borrowings, net		98,880			-			128,716			(82,587	)		145,009
Redemptions and Repayments-
Long-term debt		(1,696	)		(260,372	)		(369,519	)		8,734			(622,853	)
Short-term borrowings, net		-			(82,587	)		-			82,587			-
Net cash provided from financing activities		97,184			4,751			93,162			8,734			203,831

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(694	)		(332,789	)		(301,484	)		-			(634,967	)
Proceeds from asset sales		-			15,771			-			-			15,771
Sales of investment securities held in trusts		-			-			537,078			-			537,078
Purchases of investment securities held in trusts		-			-			(550,730	)		-			(550,730	)
Loan repayments from (loans to) associated companies, net		(261,839	)		20,669			-			-			(241,170	)
Other		65			(22,448	)		349			-			(22,034	)
Net cash used for investing activities		(262,468	)		(318,797	)		(314,787	)		-			(896,052	)

Net change in cash and cash equivalents		120,000			(5	)		-			-			119,995
Cash and cash equivalents at beginning of period		-			39			-			-			39
Cash and cash equivalents at end of period	$	120,000		$	34		$	-		$	-		$	120,034

146

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

147

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended March 31, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 1,099,848 $ 567,701 $ 325,684 $ (894,117 ) $ 1,099,116

EXPENSES:
Fuel 2,138 291,239 28,312 - 321,689
Purchased power from non-affiliates 206,724 - - - 206,724
Purchased power from affiliates 891,979 2,138 25,485 (894,117 ) 25,485
Other operating expenses 37,596 107,167 139,595 12,188 296,546
Provision for depreciation 307 26,599 24,194 (1,358 ) 49,742
General taxes 5,415 11,570 6,212 - 23,197
Total expenses 1,144,159 438,713 223,798 (883,287 ) 923,383

OPERATING INCOME (LOSS) (44,311 ) 128,988 101,886 (10,830 ) 175,733

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees 121,725 (1,208 ) (6,537 ) (116,884 ) (2,904 )
Interest expense to affiliates (82 ) (5,289 ) (1,839 ) - (7,210 )
Interest expense - other (3,978 ) (25,968 ) (11,018 ) 16,429 (24,535 )
Capitalized interest 21 6,228 414 - 6,663
Total other income (expense) 117,686 (26,237 ) (18,980 ) (100,455 ) (27,986 )

INCOME BEFORE INCOME TAXES 73,375 102,751 82,906 (111,285 ) 147,747

INCOME TAXES (BENEFIT) (16,609 ) 39,285 32,764 2,323 57,763

NET INCOME $ 89,984 $ 63,466 $ 50,142 $ (113,608 ) $ 89,984

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended March 31, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 1,019,387 $ 551,355 $ 234,091 $ (786,540 ) $ 1,018,293

EXPENSES:
Fuel 2,367 201,231 29,937 - 233,535
Purchased power from non-affiliates 186,203 2,367 - (2,367 ) 186,203
Purchased power from affiliates 784,172 59,069 17,415 (784,173 ) 76,483
Other operating expenses 51,249 99,095 113,252 - 263,596
Provision for depreciation 453 24,936 22,621 - 48,010
General taxes 4,934 10,568 6,216 - 21,718
Total expenses 1,029,378 397,266 189,441 (786,540 ) 829,545

OPERATING INCOME (LOSS) (9,991 ) 154,089 44,650 - 188,748

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees 113,948 916 5,200 (100,332 ) 19,732
Interest expense to affiliates - (24,331 ) (5,115 ) - (29,446 )
Interest expense - other (1,385 ) (6,760 ) (9,213 ) - (17,358 )
Capitalized interest 5 2,099 1,105 - 3,209
Total other income (expense) 112,568 (28,076 ) (8,023 ) (100,332 ) (23,863 )

INCOME BEFORE INCOME TAXES 102,577 126,013 36,627 (100,332 ) 164,885

INCOME TAXES 73 49,289 13,019 - 62,381

NET INCOME $ 102,504 $ 76,724 $ 23,608 $ (100,332 ) $ 102,504

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of March 31, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents $ 2 $ - $ - $ - $ 2
Receivables-
Customers 125,116 - - - 125,116
Associated companies 285,350 231,049 96,852 (295,511 ) 317,740
Other 1,174 1,050 - 2,224
Notes receivable from associated companies 668,376 - 69,011 - 737,387
Materials and supplies, at average cost 2,849 264,501 207,275 - 474,625
Prepayments and other 107,798 26,208 1,728 - 135,734
1,190,665 522,808 374,866 (295,511 ) 1,792,828

PROPERTY, PLANT AND EQUIPMENT:
In service 35,302 5,359,381 3,700,973 (391,896 ) 8,703,760
Less - Accumulated provision for depreciation 7,810 2,655,103 1,537,747 (168,115 ) 4,032,545
27,492 2,704,278 2,163,226 (223,781 ) 4,671,215
Construction work in progress 10,792 881,899 165,389 - 1,058,080
38,284 3,586,177 2,328,615 (223,781 ) 5,729,295

OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts - - 1,263,338 - 1,263,338
Long-term notes receivable from associated companies - - 62,900 - 62,900
Investment in associated companies 2,598,022 - - (2,598,022 ) -
Other 2,529 21,657 202 - 24,388
2,600,551 21,657 1,326,440 (2,598,022 ) 1,350,626

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes 10,518 495,131 - (248,666 ) 256,983
Lease assignment receivable from associated companies - 67,256 - - 67,256
Goodwill 24,248 - - 24,248
Property taxes - 25,007 22,767 - 47,774
Pension assets 3,214 12,856 - - 16,070
Unamortized sale and leaseback costs - 38,120 - 47,575 85,695
Other 18,177 49,393 5,188 (37,939 ) 34,819
56,157 687,763 27,955 (239,030 ) 532,845
$ 3,885,657 $ 4,818,405 $ 4,057,876 $ (3,356,344 ) $ 9,405,594

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt $ - $ 738,087 $ 887,265 $ (16,896 ) $ 1,608,456
Notes payable-
Associated companies - 885,760 260,199 - 1,145,959
Other 700,000 - - - 700,000
Accounts payable-
Associated companies 554,844 1,419 119,773 (270,368 ) 405,668
Other 55,614 130,090 - - 185,704
Accrued taxes 3,378 116,383 47,292 (24,219 ) 142,834
Other 85,100 107,791 9,731 45,484 248,106
1,398,936 1,979,530 1,324,260 (265,999 ) 4,436,727

CAPITALIZATION:
Common stockholder's equity 2,460,215 1,011,907 1,579,614 (2,591,521 ) 2,460,215
Long-term debt and other long-term obligations - 1,320,773 62,900 (1,305,717 ) 77,956
2,460,215 2,332,680 1,642,514 (3,897,238 ) 2,538,171

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction - - - 1,051,871 1,051,871
Accumulated deferred income taxes - - 244,978 (244,978 ) -
Accumulated deferred investment tax credits - 35,350 24,619 - 59,969
Asset retirement obligations - 24,947 798,739 - 823,686
Retirement benefits 9,332 56,016 - - 65,348
Property taxes - 25,329 22,766 - 48,095
Lease market valuation liability - 341,881 - - 341,881
Other 17,174 22,672 - - 39,846
26,506 506,195 1,091,102 806,893 2,430,696
$ 3,885,657 $ 4,818,405 $ 4,057,876 $ (3,356,344 ) $ 9,405,594

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

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

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

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

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

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

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

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

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction - - - 1,060,119 1,060,119
Accumulated deferred income taxes - - 259,147 (259,147 ) -
Accumulated deferred investment tax credits - 36,054 25,062 - 61,116
Asset retirement obligations - 24,346 785,768 - 810,114
Retirement benefits 8,721 54,415 - - 63,136
Property taxes - 25,328 22,767 - 48,095
Lease market valuation liability - 353,210 - - 353,210
Other 19,800 21,829 - - 41,629
28,521 515,182 1,092,744 800,972 2,437,419
TOTAL LIABILITIES AND CAPITALIZATION $ 3,162,511 $ 4,452,888 $ 4,092,883 $ (3,286,018 ) $ 8,422,264

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Three Months Ended March 31, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)

NET CASH PROVIDED FROM
OPERATING ACTIVITIES $ 65,870 $ 55,003 $ 177,456 $ - $ 298,329

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Equity contribution from parent 700,000 700,000 - (700,000 ) 700,000
Short-term borrowings, net 250,000 - - (52,269 ) 197,731
Redemptions and Repayments-
Long-term debt - (616,728 ) (128,716 ) - (745,444 )
Short-term borrowings, net - (52,269 ) - 52,269 -
Net cash provided from (used for) financing activities 950,000 31,003 (128,716 ) (700,000 ) 152,287

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (214 ) (81,400 ) (35,892 ) - (117,506 )
Sales of investment securities held in trusts - - 178,632 - 178,632
Purchases of investment securities held in trusts - - (188,076 ) - (188,076 )
Loans to associated companies, net (316,003 ) - (3,895 ) - (319,898 )
Investment in subsidiary (700,000 ) - - 700,000 -
Other 347 (4,606 ) 491 - (3,768 )
Net cash used for investing activities (1,015,870 ) (86,006 ) (48,740 ) 700,000 (450,616 )

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

See "Management's Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Information" in Item 2 above.

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 first 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 March 31, 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 March 31, 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 first quarter of 2008 to restate its Consolidated Statements of Cash Flows for the three months ended March 31, 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 were effective as originally filed, erroneously did not reflect the payment of common stock dividends in the first quarter 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 ~~March 31, 2008,~~June 30, 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 were effective as of the end of the period covered by this report.

(b) CHANGES IN INTERNAL CONTROLS

During the quarter ended June 30, 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.

51148

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, and Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, include a detailed discussion of its risk factors. For the quarter ended June 30, 2009, there have been no material changes to these risk factors.

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 second quarter of 2009.

	Period
	April	May	June	Second Quarter
Total Number of Shares Purchased (a)	25,666	26,682	436,452	488,800
Average Price Paid per Share	$39.08	$39.86	$38.68	$38.76
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.

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

(a)	The annual meeting of FirstEnergy shareholders was held on May 19, 2009.

(b)	At this meeting, the following persons (comprising all members of the Board) were elected to FirstEnergy's Board of Directors until the Annual Meeting of Shareholders in 2010 and until their successors have been elected:

	Number of Votes
	For		Withheld

Paul T. Addison		115,453,478		107,532,193
Anthony J. Alexander		115,319,952		107,665,719
Michael J. Anderson		115,182,823		107,802,848
Dr. Carol A. Cartwright		107,462,102		115,523,569
William T. Cottle		108,415,632		114,570,039
Robert B. Heisler, Jr.		114,997,860		107,987,811
Ernest J. Novak, Jr.		115,243,864		107,741,807
Catherine A. Rein		114,687,786		108,297,885
George M. Smart		107,568,271		115,417,400
Wes M. Taylor		115,400,913		107,584,758
Jesse T. Williams, Sr.		107,935,870		115,049,801

149

(c)

(i)

At this meeting, the appointment of PricewaterhouseCoopers LLP, an independent registered public accounting firm, as auditor for the 2009 fiscal year was ratified:

Number of Votes
For	Against	Abstentions

219,754,593	2,100,019	1,131,567

(ii)

At this meeting, a shareholder proposal recommending that the Board of Directors adopt simple majority shareholder voting was approved (approval required a favorable vote of a majority of the votes cast):

Based on this result, the Board of Directors will further review this proposal.

(iii)

At this meeting, a shareholder proposal recommending that the Board of Directors amend the company's bylaws to reduce the percentage of shareholders required to call a special shareholder meeting was approved (approval required a favorable vote of a majority of the votes cast):

Based on this result, the Board of Directors will further review this proposal.

(iv)

At this meeting, a shareholder proposal recommending that the Board of Directors adopt a policy establishing an engagement process with proponents of shareholder proposals that are supported by a majority of the votes cast, excluding abstentions and broker non-votes, at any annual meeting was not approved (approval required a favorable vote of a majority of the votes cast):

(v)	At this meeting, a shareholder proposal recommending that the Board of Directors adopt a majority vote standard for the election of directors was approved (approval required a favorable vote of a majority of the votes cast):

Based on this result, the Board of Directors will further review this proposal.

150

ITEM 6. EXHIBITS

Exhibit Number


FirstEnergy
OE	10.1		Form of Written Consent for Named Executive Officers dated June 1, 2009
	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~~	101*		The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended June 30, 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 1, 2009, by and between FirstEnergy Nuclear Generation Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.1)
		4.2	First Supplemental Indenture, dated as of June 15, 2009, to Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009, by and between FirstEnergy Nuclear Generation Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2)
		4.2(a)	Form of First Mortgage Bonds, Guarantee Series A of 2009 due 2033 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(a))
		4.2(b)	Form of First Mortgage Bonds, Guarantee Series B of 2009 due 2011 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(b))
		4.2(c)	Form of First Mortgage Bonds, Collateral Series A of 2009 due 2010 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(c))
		4.2(d)	Form of First Mortgage Bonds, Collateral Series B of 2009 due 2010 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(d))
		4.2(e)	Form of First Mortgage Bonds, Collateral Series C of 2009 due 2010 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(e))
		4.2(f)	Form of First Mortgage Bonds, Collateral Series D of 2009 due 2010 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(f))
		4.2(g)	Form of First Mortgage Bonds, Collateral Series E of 2009 due 2010 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(g))
		4.2(h)	Form of First Mortgage Bonds, Collateral Series F of 2009 due 2011 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(h))
		4.2(i)	Form of First Mortgage Bonds, Collateral Series G of 2009 due 2011 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(i))
		4.3	Second Supplemental Indenture, dated as of June 30, 2009, to Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009, by and between FirstEnergy Nuclear Generation Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1)
		4.3(a)	Form of First Mortgage Bonds, Guarantee Series C of 2009 due 2033 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1(a))

151

	4.3(b)	Form of First Mortgage Bonds, Guarantee Series D of 2009 due 2033 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1(b))
	4.3(c)	Form of First Mortgage Bonds, Guarantee Series E of 2009 due 2033 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1(c))
	4.3(d)	Form of First Mortgage Bonds, Collateral Series H of 2009 due 2011 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1(d))
	4.3(e)	Form of First Mortgage Bonds, Collateral Series I of 2009 due 2011 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1(e))
	4.3(f)	Form of First Mortgage Bonds, Collateral Series J of 2009 due 2010 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1(f))
	4.4	Fourth Supplemental Indenture, dated as of June 1, 2009, to Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, by and between FirstEnergy Generation Corp. and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A.), as trustee (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01, Exhibit 4.3(a))
	4.4(a)	Form of First Mortgage Bonds, Guarantee Series C of 2009 due 2018 (incorporated by reference to FES Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01, Exhibit 4.3(a))
	4.4(b)	Form of First Mortgage Bonds, Guarantee Series D of 2009 due 2029 (incorporated by reference to FES Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01, Exhibit 4.3(b))
	4.4(c)	Form of First Mortgage Bonds, Guarantee Series E of 2009 due 2029 (incorporated by reference to FES Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01, Exhibit 4.3(c))
	4.4(d)	Form of First Mortgage Bonds, Collateral Series B of 2009 due 2011 (incorporated by reference to FES Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01, Exhibit 4.3(d))
	4.4(e)	Form of First Mortgage Bonds, Collateral Series C of 2009 due 2011 (incorporated by reference to FES Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01, Exhibit 4.3(e))
	4.5	Fifth Supplemental Indenture, dated as of June 30, 2009, to Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, by and between FirstEnergy Generation Corp. and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A.), as trustee (incorporated by reference to FES’ Form 8-K (SEC File No. 333-145140-01) filed on July 6, 2009, Exhibit 4.2)
	4.5(a)	Form of First Mortgage Bonds, Guarantee Series F of 2009 due 2047 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(a))
	4.5(b)	Form of First Mortgage Bonds, Guarantee Series G of 2009 due 2018 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(b))
	4.5(c)	Form of First Mortgage Bonds, Guarantee Series H of 2009 due 2018 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(c))
	10.2	Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp.
	(A) 10.2	Form of Amendment No. 2 to Letter of Credit and Reimbursement Agreement, dated as of June 12, 2009, by and among FirstEnergy Nuclear Generation Corp., FirstEnergy Corp. and FirstEnergy Solutions Corp., as guarantors, the banks party thereto, and Barclays Bank PLC, as fronting Bank and administrative agent, to Letter of Credit and Reimbursement Agreement dated as of December 16, 2005 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 10.1)

152

	(B) 10.3	Form of Amendment No. 2 to Letter of Credit and Reimbursement Agreement, dated as of June 12, 2009, by and among FirstEnergy Generation Corp., FirstEnergy Corp. and FirstEnergy Solutions Corp., as guarantors, the banks party thereto, Barclays Bank PLC, as fronting Bank and administrative agent and KeyBank National Association, as syndication agent, to Letter of Credit and Reimbursement Agreement dated as of April 3, 2006 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 10.2)
	10.4	Surplus Margin Guaranty, dated as of June 16, 2009, made by FirstEnergy Nuclear Generation Corp. in favor of The Cleveland Electric Illuminating Company, The Toledo Edison Company and Ohio Edison Company (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 10.3)
	12	Fixed charge ratios
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
OE
	10.2	Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp.
	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 CEI
	10.2	Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp.
	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~~ TE
	10.2	Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp.
	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
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

153

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

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

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

* 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, 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.

52154

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~~August 3, 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)

53155

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

000-53742	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 ~~MAY 8, 2008~~August 3, 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, ~~Inc.,~~Incorporated, 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
~~TEBSA~~Waverly	~~Termobarranquila S.A. Empresa de Servicios Publicos~~	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:

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
~~BPJ~~	~~Best Professional Judgment~~
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~~
~~EITF~~	~~Emerging Issues Task Force~~Rate Counsel
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
	Results of Operations	1-44
	Report of Independent Registered Public Accounting Firm	45
	Consolidated Statements of Income	46
	Consolidated Statements of Comprehensive Income	47
	Consolidated Balance Sheets	48
	Consolidated Statements of Cash Flows	49

FirstEnergy Solutions Corp.

	Management's Narrative Analysis of Results of Operations	50-53
	Report of Independent Registered Public Accounting Firm	54
	Consolidated Statements of Income and Comprehensive Income	55
	Consolidated Balance Sheets	56
	Consolidated Statements of Cash Flows	57

Ohio Edison Company

	Management's Narrative Analysis of Results of Operations	58-59
	Report of Independent Registered Public Accounting Firm	260
	Consolidated Statements of Income and Comprehensive Income	361
	Consolidated Balance Sheets	462
	Consolidated Statements of Cash Flows	563

The Cleveland Electric Illuminating Company

	Management's Narrative Analysis of Results of Operations	64-65
	Report of Independent Registered Public Accounting Firm	666
	Consolidated Statements of Income and Comprehensive Income	767
	Consolidated Balance Sheets	868
	Consolidated Statements of Cash Flows	969

The Toledo Edison Company

	Management's Narrative Analysis of Results of Operations	70-71
	Report of Independent Registered Public Accounting Firm	1072
	Consolidated Statements of Income and Comprehensive Income	1173
	Consolidated Balance Sheets	1274
	Consolidated Statements of Cash Flows	1375

~~FIN 47~~	~~FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB~~ ~~Statement No. 143"~~
~~FIN 48~~	~~FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement~~ ~~No. 109”~~
~~FirstCom~~	~~First Communications, Inc.~~
FMB	First Mortgage ~~Bonds~~Bond
FSP	FASB Staff Position
FSP FAS ~~157-2~~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 ~~157-2, “Effective Date of FASB Statement No. 157”~~132(R)-1, "Employers' Disclosures about Postretirement Benefit Plan Assets"
~~FTR~~FSP FAS 157-4	~~Financial Transmission Rights~~ 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"
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~~
MISO	Midwest Independent Transmission System Operator, Inc.
~~Moody’s~~Moody's	~~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~~OCI	~~Office of Consumer Advocate~~Other Comprehensive Income
~~OTC~~OPEB	~~Over the Counter~~Other Post-Employment Benefits
OVEC	Ohio Valley Electric Corporation
PCRB	Pollution Control Revenue Bond
~~PICA~~	~~Penelec Industrial Customer Alliance~~
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last ~~Resort~~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~~RTC	~~Reliability Pricing Model~~
~~RSP~~	~~Rate Stabilization Plan~~	Regulatory Transition Charge
RTO	Regional Transmission Organization
S&P	Standard & ~~Poor’s~~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 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS ~~109~~107	SFAS No. ~~109, “Accounting for Income Taxes”~~	107, "Disclosure about Fair Value of Financial Instruments"
SFAS ~~123(R)~~115	SFAS No. ~~123(R), "Share-Based Payment"~~	115, "Accounting for Certain Investments in Debt and Equity Securities"
SFAS 133	SFAS No. 133, ~~“Accounting~~"Accounting for Derivative Instruments and Hedging ~~Activities”~~Activities"
SFAS 140	SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities – a replacement of FASB Statement No. 125”

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~~"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”~~ Measurements"
SFAS 160	SFAS No. 160, ~~“Noncontrolling~~"Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. ~~51”~~51"
SFAS ~~161~~166	SFAS ~~No 161, “Disclosure about Derivative Instruments and Hedging Activities~~No. 166, “Accounting for Transfers of Financial Assets – an ~~Amendment~~amendment of FASB Statement No. 140”
SFAS 167	SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)”
SFAS 168	SFAS No. 168, “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. ~~133”~~162”
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 Periods	Three Months Ended June 30				Six Months Ended June 30

Basic Earnings Per Share – 2008		$	0.86			$	1.77
Gain on non-core asset sales	0.52				0.46
Regulatory charges – 2009	-				(0.55			)
Income tax resolution – 2009	-				0.04
Organizational restructuring costs – 2009	(0.01			)	(0.06			)
Debt redemption premium / Penelec strike costs – 2009	(0.01			)	(0.01			)
Litigation settlement – 2008	(0.03			)	(0.03			)
Trust securities impairment	0.04				(0.01			)
Revenues (excluding asset sales)	(0.44			)	(0.26			)
Fuel and purchased power	0.17				(0.07			)
Transmission costs	0.20				0.26
Amortization of regulatory assets, net	(0.08			)	0.04
Other expenses		0.14				0.17
Basic Earnings Per Share – 2009		$	1.36			$	1.75

Electric Distribution KWH Deliveries
Residential	(2.8	)%
Commercial	(3.8	)%
Industrial	(20.8	)%
Total Distribution KWH Deliveries	(9.4	)%

OE

	Three Months
	Ended March 31, 2008
	As Previously			As
	Reported			Restated
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	43,909		$	43,909
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		21,493			21,493
Amortization of regulatory assets		48,538			48,538
Deferral of new regulatory assets		(25,411	)		(25,411	)
Amortization of lease costs		32,934			32,934
Deferred income taxes and investment tax credits, net		6,866			6,866
Accrued compensation and retirement benefits		(19,482	)		(19,482	)
Increase in operating assets-
Receivables		(27,496	)		(27,496	)
Prepayments and other current assets		(7,451	)		(7,451	)
Increase (decrease) in operating liabilities-
Accounts payable		(18,939	)		(3,939	)
Accrued taxes		2,991			2,991
Accrued interest		(5,919	)		(5,919	)
Electric service prepayment programs		(10,028	)		(10,028	)
Other		(2,066	)		(2,066	)
Net cash provided from operating activities		39,939			54,939

CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt		(80	)		(80	)
Dividend Payments-
Common stock		-			(15,000	)
Net cash used for financing activities		(80	)		(15,080	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(49,011	)		(49,011	)
Sales of investment securities held in trusts		62,344			62,344
Purchases of investment securities held in trusts		(63,797	)		(63,797	)
Loan repayments from associated companies, net		6,534			6,534
Cash investments		147			147
		3,924			3,924
Net cash used for investing activities		(39,859	)		(39,859	)

Net change in cash and cash equivalents	$	-		$	-

Reconciliation of Basic and Diluted		Three Months Ended March 31,
Earnings per Share of Common Stock		2008		2007
	(In millions, except per share amounts)
Net income		$	276	$	290

Average shares of common stock outstanding – Basic			304		314
Assumed exercise of dilutive stock options and awards			3		2
Average shares of common stock outstanding – Dilutive			307		316

Basic earnings per share of common stock		$	0.91	$	0.92
Diluted earnings per share of common stock		$	0.90	$	0.92

	March 31, 2008
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
	(In millions)
Assets:
Derivatives	$	4	$	98	$	-	$	102
Nuclear decommissioning trusts(1)		1,070		953		-		2,023
Other investments(2)		21		303		-		324
Total	$	1,095	$	1,354	$	-	$	2,449

Liabilities:
Derivatives	$	-	$	98	$	-	$	98
NUG contracts(3)		-		-		682		682
Total	$	-	$	98	$	682	$	780

Balance as of January 1, 2008	$	750
Realized and unrealized gains (losses)(1)		(58	)
Purchases, sales, issuances and settlements, net(1)		(10	)
Net transfers to (from) Level 3		-
Balance as of March 31, 2008	$	682

Change in unrealized gains (losses) relating to
instruments held as of March 31, 2008	$	(58	)

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

ARO Reconciliation	FirstEnergy		FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Balance, January 1, 2008	$	1,267	$	810	$	94	$	2	$	28	$	90	$	161	$	82
Liabilities incurred		-		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-		-
Accretion		20		14		1		-		1		1		2		1
Revisions in estimated cash flows		-		-		-		-		-		-		-		-
Balance, March 31, 2008	$	1,287	$	824	$	95	$	2	$	29	$	91	$	163	$	83

Balance, January 1, 2007	$	1,190	$	760	$	88	$	2	$	27	$	84	$	151	$	77
Liabilities incurred		-		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-		-
Accretion		18		12		1		-		-		2		2		1
Revisions in estimated cash flows		-		-		-		-		-		-		-		-
Balance, March 31, 2007	$	1,208	$	772	$	89	$	2	$	27	$	86	$	153	$	78

	Pension Benefit Cost (Credit)						Other Postretirement Benefit Cost (Credit)
	2008			2007			2008			2007
	(In millions)
FES	$	4		$	-		$	(2	)	$	-
OE		(7	)		(4	)		(2	)		(3	)
CEI		(1	)		-			1			1
TE		(1	)		-			1			1
JCP&L		(4	)		(2	)		(4	)		(4	)
Met-Ed		(3	)		(2	)		(3	)		(2	)
Penelec		(3	)		(3	)		(3	)		(3	)
Other FirstEnergy subsidiaries		(4	)		3			(3	)		(6	)
	$	(19	)	$	(8	)	$	(15	)	$	(16	)

	Maximum Exposure		Discounted Lease Payments, net		Net Exposure
	(in millions)
FES	$	1,364	$	1,216	$	148
OE	819		628		191
CEI	782		77		705
TE	782		457		325

	Three Months Ended
	March 31,
	2008		2007
	(In millions)
JCP&L	$	19	$	20
Met-Ed		16		15
Penelec		8		8
	$	43	$	43

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended March 31, 2008	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)

REVENUES	$	1,099,848		$	567,701		$	325,684		$	(894,117	)	$	1,099,116

EXPENSES:
Fuel		2,138			291,239			28,312			-			321,689
Purchased power from non-affiliates		206,724			-			-			-			206,724
Purchased power from affiliates		891,979			2,138			25,485			(894,117	)		25,485
Other operating expenses		37,596			107,167			139,595			12,188			296,546
Provision for depreciation		307			26,599			24,194			(1,358	)		49,742
General taxes		5,415			11,570			6,212			-			23,197
Total expenses		1,144,159			438,713			223,798			(883,287	)		923,383

OPERATING INCOME (LOSS)		(44,311	)		128,988			101,886			(10,830	)		175,733

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		121,725			(1,208	)		(6,537	)		(116,884	)		(2,904	)
Interest expense to affiliates		(82	)		(5,289	)		(1,839	)		-			(7,210	)
Interest expense - other		(3,978	)		(25,968	)		(11,018	)		16,429			(24,535	)
Capitalized interest		21			6,228			414			-			6,663
Total other income (expense)		117,686			(26,237	)		(18,980	)		(100,455	)		(27,986	)

INCOME BEFORE INCOME TAXES		73,375			102,751			82,906			(111,285	)		147,747

INCOME TAXES (BENEFIT)		(16,609	)		39,285			32,764			2,323			57,763

NET INCOME	$	89,984		$	63,466		$	50,142		$	(113,608	)	$	89,984

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of March 31, 2008	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	2	$	-	$	-	$	-		$	2
Receivables-
Customers		125,116		-		-		-			125,116
Associated companies		285,350		231,049		96,852		(295,511	)		317,740
Other		1,174		1,050		-					2,224
Notes receivable from associated companies		668,376		-		69,011		-			737,387
Materials and supplies, at average cost		2,849		264,501		207,275		-			474,625
Prepayments and other		107,798		26,208		1,728		-			135,734
		1,190,665		522,808		374,866		(295,511	)		1,792,828

PROPERTY, PLANT AND EQUIPMENT:
In service		35,302		5,359,381		3,700,973		(391,896	)		8,703,760
Less - Accumulated provision for depreciation		7,810		2,655,103		1,537,747		(168,115	)		4,032,545
		27,492		2,704,278		2,163,226		(223,781	)		4,671,215
Construction work in progress		10,792		881,899		165,389		-			1,058,080
		38,284		3,586,177		2,328,615		(223,781	)		5,729,295

OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,263,338		-			1,263,338
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		2,598,022		-		-		(2,598,022	)		-
Other		2,529		21,657		202		-			24,388
		2,600,551		21,657		1,326,440		(2,598,022	)		1,350,626

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		10,518		495,131		-		(248,666	)		256,983
Lease assignment receivable from associated companies		-		67,256		-		-			67,256
Goodwill		24,248				-		-			24,248
Property taxes		-		25,007		22,767		-			47,774
Pension assets		3,214		12,856		-		-			16,070
Unamortized sale and leaseback costs		-		38,120		-		47,575			85,695
Other		18,177		49,393		5,188		(37,939	)		34,819
		56,157		687,763		27,955		(239,030	)		532,845
	$	3,885,657	$	4,818,405	$	4,057,876	$	(3,356,344	)	$	9,405,594

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	-	$	738,087	$	887,265	$	(16,896	)	$	1,608,456
Notes payable-
Associated companies		-		885,760		260,199		-			1,145,959
Other		700,000		-		-		-			700,000
Accounts payable-
Associated companies		554,844		1,419		119,773		(270,368	)		405,668
Other		55,614		130,090		-		-			185,704
Accrued taxes		3,378		116,383		47,292		(24,219	)		142,834
Other		85,100		107,791		9,731		45,484			248,106
		1,398,936		1,979,530		1,324,260		(265,999	)		4,436,727

CAPITALIZATION:
Common stockholder's equity		2,460,215		1,011,907		1,579,614		(2,591,521	)		2,460,215
Long-term debt and other long-term obligations		-		1,320,773		62,900		(1,305,717	)		77,956
		2,460,215		2,332,680		1,642,514		(3,897,238	)		2,538,171

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,051,871			1,051,871
Accumulated deferred income taxes		-		-		244,978		(244,978	)		-
Accumulated deferred investment tax credits		-		35,350		24,619		-			59,969
Asset retirement obligations		-		24,947		798,739		-			823,686
Retirement benefits		9,332		56,016		-		-			65,348
Property taxes		-		25,329		22,766		-			48,095
Lease market valuation liability		-		341,881		-		-			341,881
Other		17,174		22,672		-		-			39,846
		26,506		506,195		1,091,102		806,893			2,430,696
	$	3,885,657	$	4,818,405	$	4,057,876	$	(3,356,344	)	$	9,405,594

Number of Votes

Abstentions