JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2010			2009
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1		$	27
Receivables-
Customers (less accumulated provisions of $3,668,000 and $3,506,000
respectively, for uncollectible accounts)		282,611			300,991
Associated companies		42			12,884
Other		19,842			21,877
Notes receivable - associated companies		110,552			102,932
Prepaid taxes		17,044			34,930
Other		14,370			12,945
		444,462			486,586
UTILITY PLANT:
In service		4,493,540			4,463,490
Less - Accumulated provision for depreciation		1,630,664			1,617,639
		2,862,876			2,845,851
Construction work in progress		49,025			54,251
		2,911,901			2,900,102
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		202,532			199,677
Nuclear plant decommissioning trusts		172,984			166,768
Other		2,158			2,149
		377,674			368,594
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,810,936			1,810,936
Regulatory assets		855,740			888,143
Other		22,902			27,096
		2,689,578			2,726,175
	$	6,423,615		$	6,481,457
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	31,084		$	30,639
Accounts payable-
Associated companies		24,346			26,882
Other		139,945			168,093
Accrued taxes		42,274			12,594
Accrued interest		30,072			18,256
Other		98,468			111,156
		366,189			367,620
CAPITALIZATION
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares-
13,628,447 shares outstanding		136,284			136,284
Other paid-in capital		2,506,864			2,507,049
Accumulated other comprehensive loss		(233,573	)		(243,012	)
Retained earnings		139,300			200,075
Total common stockholder's equity		2,548,875			2,600,396
Long-term debt and other long-term obligations		1,794,558			1,801,589
		4,343,433			4,401,985
NONCURRENT LIABILITIES:
Power purchase contract liability		399,762			399,105
Accumulated deferred income taxes		701,998			687,545
Nuclear fuel disposal costs		196,551			196,511
Asset retirement obligations		103,209			101,568
Retirement benefits		131,718			150,603
Other		180,755			176,520
		1,713,993			1,711,852
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	6,423,615		$	6,481,457

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

~~Revenues –~~

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

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 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 economic conditions in the Ohio Companies' service territory. Average prices increased primarily due to an increase in the Ohio Companies' fuel cost recovery riders that were 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 $5 million resulted from the termination of the 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 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 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 first six months of 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 Ohio Companies' generation leasehold interests. The amortization of regulatory assets increased by $75 million in the first six months of 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 PUCO.

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31
	2010			2009
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	29,226		$	27,558
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		27,971			25,103
Amortization of regulatory assets, net		69,448			86,831
Deferred purchased power and other costs		(32,775	)		(28,369	)
Deferred income taxes and investment tax credits, net		(2,082	)		(6,408	)
Accrued compensation and retirement benefits		(5,847	)		(7,481	)
Cash collateral returned to suppliers		(23,400	)		(209	)
Decrease in operating assets:
Receivables		33,257			27,143
Prepayments and other current assets		16,472			4,792
Increase (decrease) in operating liabilities:
Accounts payable		(40,992	)		(30,029	)
Accrued taxes		50,857			33,114
Accrued interest		11,816			21,249
Tax collections payable		14,544			5,935
Other		466			1,955
Net cash provided from operating activities		148,961			161,184

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			299,619
Redemptions and Repayments-
Common stock		-			(150,000	)
Long-term debt		(6,773	)		(6,402	)
Short-term borrowings, net		-			(121,380	)
Dividend Payments-
Common stock		(90,000	)		(63,000	)
Other		-			(2,152	)
Net cash used for financing activities		(96,773	)		(43,315	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(37,338	)		(37,372	)
Loans to associated companies, net		(7,620	)		(75,108	)
Sales of investment securities held in trusts		190,198			115,483
Purchases of investment securities held in trusts		(194,748	)		(120,062	)
Other		(2,706	)		(872	)
Net cash used for investing activities		(52,214	)		(117,931	)

Net change in cash and cash equivalents		(26	)		(62	)
Cash and cash equivalents at beginning of period		27			66
Cash and cash equivalents at end of period	$	1		$	4

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

~~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):

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.

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2010			2009
	(In thousands)

REVENUES:
Electric sales	$	451,560		$	409,686
Gross receipts tax collections		21,567			19,983
Total revenues		473,127			429,669

EXPENSES:
Purchased power from affiliates		161,080			100,077
Purchased power from non-affiliates		91,928			123,911
Other operating costs		101,983			106,357
Provision for depreciation		12,758			12,139
Amortization of regulatory assets, net		48,800			27,591
General taxes		21,740			21,935
Total expenses		438,289			392,010

OPERATING INCOME		34,838			37,659

OTHER INCOME (EXPENSE):
Interest income		1,217			3,186
Miscellaneous income		2,173			856
Interest expense		(13,773	)		(13,359	)
Capitalized interest		126			15
Total other expense		(10,257	)		(9,302	)

INCOME BEFORE INCOME TAXES		24,581			28,357

INCOME TAXES		12,266			11,735

NET INCOME		12,315			16,622

OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		9,709			4,553
Unrealized gain on derivative hedges		84			84
Other comprehensive income		9,793			4,637
Income tax expense related to other comprehensive income		4,177			1,793
Other comprehensive income, net of tax		5,616			2,844

TOTAL COMPREHENSIVE INCOME	$	17,931		$	19,466

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

~~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:

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.~~

METROPOLITAN EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2010			2009
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	128		$	120
Receivables-
Customers (less accumulated provisions of $4,341,000 and $4,044,000,
respectively, for uncollectible accounts)		171,347			171,052
Associated companies		40,651			29,413
Other		11,189			11,650
Notes receivable from associated companies		11,767			97,150
Prepaid taxes		67,672			15,229
Other		1,057			1,459
		303,811			326,073
UTILITY PLANT:
In service		2,178,625			2,162,815
Less - Accumulated provision for depreciation		818,724			810,746
		1,359,901			1,352,069
Construction work in progress		20,450			14,901
		1,380,351			1,366,970
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		275,356			266,479
Other		888			890
		276,244			267,369
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		416,499			416,499
Regulatory assets		392,651			356,754
Power purchase contract asset		136,702			176,111
Other		41,513			36,544
		987,365			985,908
	$	2,947,771		$	2,946,320
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	28,500		$	128,500
Short-term borrowings-
Associated companies		48,793			-
Accounts payable-
Associated companies		51,742			40,521
Other		22,550			41,050
Accrued taxes		31,130			11,170
Accrued interest		11,688			17,362
Other		25,971			24,520
		220,374			263,123
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,500 shares outstanding		1,196,943			1,197,070
Accumulated other comprehensive loss		(137,935	)		(143,551	)
Retained Earnings		16,714			4,399
Total common stockholder's equity		1,075,722			1,057,918
Long-term debt and other long-term obligations		713,900			713,873
		1,789,622			1,771,791
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		457,231			453,462
Accumulated deferred investment tax credits		7,201			7,313
Nuclear fuel disposal costs		44,400			44,391
Asset retirement obligations		183,309			180,297
Retirement benefits		30,288			33,605
Power purchase contract liability		167,120			143,135
Other		48,226			49,203
		937,775			911,406
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	2,947,771		$	2,946,320

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

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

~~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:~~

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.

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31
	2010			2009
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	12,315		$	16,622
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		12,758			12,139
Amortization of regulatory assets, net		48,800			27,591
Deferred costs recoverable as regulatory assets		(18,276	)		(19,633	)
Deferred income taxes and investment tax credits, net		(10,308	)		4,657
Accrued compensation and retirement benefits		(2,527	)		1,029
Cash collateral to suppliers		(700	)		(9,500	)
Increase in operating assets-
Receivables		(5,083	)		(9,860	)
Prepayments and other current assets		(52,040	)		(50,422	)
Increase (decrease) in operating liabilities-
Accounts payable		(7,279	)		(8,058	)
Accrued taxes		19,960			(7,749	)
Accrued interest		(5,674	)		4,803
Other		2,373			2,460
Net cash used for operating activities		(5,681	)		(35,921	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			300,000
Short-term borrowings, net		48,793			-
Redemptions and Repayments-
Long-term debt		(100,000	)		-
Short-term borrowings, net		-			(15,003	)
Other		-			(2,150	)
Net cash provided from (used for) financing activities		(51,207	)		282,847

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(25,526	)		(25,922	)
Sales of investment securities held in trusts		143,713			27,800
Purchases of investment securities held in trusts		(146,056	)		(29,821	)
Loan repayments from (loans to) associated companies, net		85,383			(218,168	)
Other		(618	)		(832	)
Net cash provided from (used for) investing activities		56,896			(246,943	)

Net increase (decrease) in cash and cash equivalents		8			(17	)
Cash and cash equivalents at beginning of period		120			144
Cash and cash equivalents at end of period	$	128		$	127

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

~~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."

~~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~~

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2010			2009
	(In thousands)

REVENUES:
Electric sales	$	385,936		$	371,293
Gross receipts tax collections		17,524			17,292
Total revenues		403,460			388,585

EXPENSES:
Purchased power from affiliates		168,400			96,081
Purchased power from non-affiliates		91,423			127,166
Other operating costs		72,394			77,289
Provision for depreciation		14,682			14,455
Amortization (deferral) of regulatory assets, net		(9,966	)		8,776
General taxes		16,534			20,593
Total expenses		353,467			344,360

OPERATING INCOME		49,993			44,225

OTHER INCOME (EXPENSE):
Miscellaneous income		1,613			798
Interest expense		(17,290	)		(13,233	)
Capitalized interest		140			22
Total other expense		(15,537	)		(12,413	)

INCOME BEFORE INCOME TAXES		34,456			31,812

INCOME TAXES		17,157			13,122

NET INCOME		17,299			18,690

OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		8,547			2,955
Unrealized gain on derivative hedges		16			16
Change in unrealized gain on available-for-sale securities		-			(22	)
Other comprehensive income		8,563			2,949
Income tax expense related to other comprehensive income		3,284			1,055
Other comprehensive income, net of tax		5,279			1,894

TOTAL COMPREHENSIVE INCOME	$	22,578		$	20,584

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

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 currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by FirstEnergy’s subsidiaries. In addition to paying dividends from retained earnings, each of FirstEnergy’s electric utility subsidiaries has authorization from the FERC to pay cash dividends from paid-in capital accounts, as long as the subsidiary’s debt to total capitalization ratio (without consideration of retained earnings) remains below 65%. CEI and TE are the 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 Operations above). Net cash provided from operating activities was $1.1 billion and $319 million in the 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 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 higher net amortization of regulatory assets, including CEI’s $216 million regulatory asset impairment, and changes in accrued compensation and retirement benefits. The change in accrued compensation and retirement benefits resulted 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 payments and an increase in other accrued expenses principally associated with 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 compared to $1.2 billion in the first six months of 2008. The decrease was primarily due to reduced short-term borrowings, partially offset by long-term debt issuances in the first six months of 2009. The following table summarizes security issuances (net of any discounts) and redemptions.

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2010			2009
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	12		$	14
Receivables-
Customers (less accumulated provisions of $3,768,000 and $3,483,000,
respectively, for uncollectible accounts)		138,010			139,302
Associated companies		92,197			77,338
Other		14,696			18,320
Notes receivable from associated companies		14,311			14,589
Prepaid taxes		69,403			18,946
Other		1,128			1,400
		329,757			269,909
UTILITY PLANT:
In service		2,453,558			2,431,737
Less - Accumulated provision for depreciation		908,550			901,990
		1,545,008			1,529,747
Construction work in progress		22,966			24,205
		1,567,974			1,553,952
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		147,757			142,603
Non-utility generation trusts		120,764			120,070
Other		287			289
		268,808			262,962
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		768,628			768,628
Regulatory assets		119,483			9,045
Power purchase contract asset		5,456			15,362
Other		17,447			19,143
		911,014			812,178
	$	3,077,553		$	2,899,001
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	69,310		$	69,310
Short-term borrowings-
Associated companies		92,807			41,473
Accounts payable-
Associated companies		56,911			39,884
Other		23,680			41,990
Accrued taxes		4,267			6,409
Accrued interest		24,480			17,598
Other		23,300			22,741
		294,755			239,405
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		913,403			913,437
Accumulated other comprehensive loss		(156,825	)		(162,104	)
Retained earnings		108,800			91,501
Total common stockholder's equity		953,930			931,386
Long-term debt and other long-term obligations		1,072,190			1,072,181
		2,026,120			2,003,567
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		274,846			242,040
Retirement benefits		166,509			174,306
Asset retirement obligations		93,374			91,841
Power purchase contract liability		171,244			100,849
Other		50,705			46,993
		756,678			656,029
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	3,077,553		$	2,899,001

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

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 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.

~~Cash Flows From Investing Activities~~

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 distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for the six months ended June 30, 2009 and 2008 by business segment:

Summary of Cash Flows Property
Provided from (Used for) Investing Activities Additions Investments Other Total
Sources (Uses) (In millions)
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
)

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31
	2010			2009
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	17,299		$	18,690
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		14,682			14,455
Amortization (deferral) of regulatory assets, net		(9,966	)		8,776
Deferred costs recoverable as regulatory assets		(20,461	)		(20,022	)
Deferred income taxes and investment tax credits, net		21,772			11,833
Accrued compensation and retirement benefits		(169	)		431
Cash collateral		(400	)		-
Increase in operating assets-
Receivables		(4,641	)		(1,709	)
Prepayments and other current assets		(50,186	)		(49,707	)
Increase (Decrease) in operating liabilities-
Accounts payable		(1,348	)		(5,340	)
Accrued taxes		(2,142	)		(9,065	)
Accrued interest		6,882			599
Other		7,162			(988	)
Net cash used for operating activities		(21,516	)		(32,047	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		51,334			80,632
Dividend Payments-
Common stock		-			(15,000	)
Other		(6	)		-
Net cash provided from financing activities		51,328			65,632

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(27,388	)		(28,190	)
Sales of investment securities held in trusts		93,057			18,800
Purchases of investment securities held in trusts		(94,464	)		(22,108	)
Loan repayments to associated companies, net		279			(365	)
Other		(1,298	)		(1,732	)
Net cash used for investing activities		(29,814	)		(33,595	)

Net change in cash and cash equivalents		(2	)		(10	)
Cash and cash equivalents at beginning of period		14			23
Cash and cash equivalents at end of period	$	12		$	13

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

COMBINED NOTES TO THE 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 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, 2009 for FirstEnergy, FES and the Utilities, as applicable. 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 when it is determined that it is the primary beneficiary (see Note 6). Investments in affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but are not the primary beneficiary and do not exercise control, 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.

2. EARNINGS PER SHARE

Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:

	Three Months Ended
Reconciliation of Basic and Diluted Earnings per Share	March 31
of Common Stock	2010		2009
	(In millions, except per share amounts)
Earnings available to FirstEnergy Corp.	$	155	$	119

Weighted average number of basic shares outstanding		304		304
Assumed exercise of dilutive stock options and awards		2		2
Weighted average number of diluted shares outstanding		306		306

Basic earnings per share of common stock	$	0.51	$	0.39
Diluted earnings per share of common stock	$	0.51	$	0.39

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 March 31, 2010 and December 31, 2009:

	March 31, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
FirstEnergy	$	13,581	$	14,373	$	13,753	$	14,502
FES		4,224		4,366		4,224		4,306
OE		1,167		1,293		1,169		1,299
CEI		1,853		2,018		1,873		2,032
TE		600		639		600		638
JCP&L		1,833		1,932		1,840		1,950
Met-Ed		742		808		842		909
Penelec		1,144		1,186		1,144		1,177

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, available-for-sale securities, and notes receivable.

Available-For-Sale Securities

The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments held in nuclear decommissioning trusts, nuclear fuel disposal trusts and NUG trusts as of March 31, 2010 and December 31, 2009:

	March 31, 2010(1)								December 31, 2009(2)
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
Debt securities	(In millions)
FirstEnergy	$	1,741	$	23	$	-	$	1,764	$	1,727	$	22	$	-	$	1,749
FES		1,052		8		-		1,060		1,043		3		-		1,046
OE		55		-		-		55		55		-		-		55
TE		72		-		-		72		72		-		-		72
JCP&L		264		8		-		272		271		9		-		280
Met-Ed		127		3		-		130		120		5		-		125
Penelec		171		4		-		175		166		5		-		171

Equity securities
FirstEnergy	$	268	$	42	$	-	$	310	$	252	$	43	$	-	$	295
FES		-		-		-		-		-		-		-		-
OE		-		-		-		-		-		-		-		-
JCP&L		80		9		-		89		74		11		-		85
Met-Ed		125		22		-		147		117		23		-		140
Penelec		63		11		-		74		61		9		-		70

(1) Excludes cash balances: FirstEnergy - $131 million; FES - $32 million; OE - $65 million; TE - $1 million; JCP&L - $15 million; Met-Ed - $(2) million and Penelec - $20 million. (2) Excludes cash balances: FirstEnergy - $137 million; FES - $43 million; OE - $66 million; TE - $2 million; JCP&L - $3 million and Penelec - $23 million.

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income for the three-month period ended March 31, 2010 were as follows:

	FirstEnergy		FES		OE		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Proceeds from sales	$	733	$	272	$	3	$	31	$	190	$	144	$	93
Realized gains		36		13		-		-		8		9		6
Realized losses		50		24		-		-		8		11		7
Interest and dividend income		21		13		-		1		4		2		1

~~Net~~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 as of March 31, 2010 and December 31, 2009 (excluding emission allowances, employee benefits, cost method investments and equity method investments of $251 million and $264 million, respectively, that are not required to be disclosed):

	March 31, 2010								December 31, 2009
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
Debt securities	(In millions)
FirstEnergy	$	494	$	76	$	-	$	570	$	544	$	72	$	-	$	616
OE		217		42		-		259		217		29		-		246
CEI		340		33		-		373		389		43		-		432

Notes Receivable

The following table provides the approximate fair value and related carrying amounts of notes receivable as of March 31, 2010 and December 31, 2009:

	March 31, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Notes receivable	(In millions)
FirstEnergy	$	36	$	35	$	36	$	35
FES		1		1		2		1
OE		-		-		-		-
TE		104		115		124		141

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 2010 to 2040.

(C)	RECURRING FAIR VALUE MEASUREMENTS

On January 1, 2010, FirstEnergy adopted the FASB Accounting Standards Update (Update) applicable to the Fair Value Measurements and Disclosures Topic. The Update provides amendments that require new disclosures surrounding (1) transfers of Level 1 and Level 2 fair value measurements, including the reason for transfers; (2) purchases, sales, issuances and settlements of Level 3 fair value measurements; (3) additional disaggregation of fair value measurements for each class of assets and liabilities; and (4) inputs and valuation techniques used to measure fair value for both recurring and nonrecurring fair value measurements.

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. A fair value hierarchy has been established 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 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 assets and liabilities consist 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 and 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 long 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 appropria te FirstEnergy management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. FirstEnergy’s Level 3 instruments consist exclusively of NUG contracts.

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

The following tables set forth financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of March 31, 2010 and December 31, 2009. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair valuation of assets and liabilities and their placement within the fair value hierarchy levels.

	Recurring Fair Value Measures as of March 31, 2010
	Level 1
Assets		FirstEnergy		FES		TE		OE		JCP&L		Met-Ed		Penelec

Nuclear Decommissioning Trust Investments
Equity securities - consumer products	$	136	$	-	$	-	$	-	$	39	$	65	$	32
Equity securities - technology		59		-		-		-		17		28		14
Equity securities - utilities & energy		59		-		-		-		17		28		14
Equity securities - financial		48		-		-		-		14		23		11
Equity securities - other		8		-		-		-		2		3		3
Total nuclear decommissioning trust investments	$	310	$	-	$	-	$	-	$	89	$	147	$	74
Total assets(1)	$	310	$	-	$	-	$	-	$	89	$	147	$	74

Liabilities

Derivatives – commodity contracts	$	8	$	8	$	-	$	-	$	-	$	-	$	-
Total liabilities	$	8	$	8	$	-	$	-	$	-	$	-	$	-

	Level 2
Assets		FirstEnergy		FES		TE		OE		JCP&L		Met-Ed		Penelec

Nuclear Decommissioning Trust Investments
Debt securities issued by the U.S. government	$	595	$	345	$	66	$	56	$	32	$	88	$	8
Debt securities issued by states of the U.S.		90		-		-		-		30		1		59
Debt securities issued by foreign governments		299		299		-		-		-		-		-
Corporate debt securities		486		413		7		-		21		39		6
Other		90		23		-		65		1		-		1
Total nuclear decommissioning trust investments	$	1,560	$	1,080	$	73	$	121	$	84	$	128	$	74

Rabbi Trust Investments
Equity securities - financial	$	1	$	-	$	-	$	-	$	-	$	-	$	-
Other		11		-		-		1		-		-		-
Total rabbi trust investments	$	12	$	-	$	-	$	1	$	-	$	-	$	-

Nuclear Fuel Disposal Trust Investments
Debt securities issued by states of the U.S.	$	201	$	-	$	-	$	-	$	201	$	-	$	-
Other		2		-		-		-		2		-		-
Total nuclear fuel disposal trust investments	$	203	$	-	$	-	$	-	$	203	$	-	$	-

NUG Trust Investments
Debt securities issued by states of the U.S.	$	98	$	-	$	-	$	-	$	-	$	-	$	98
Other		23		-		-		-		-		-		23
Total NUG trust investments	$	121	$	-	$	-	$	-	$	-	$	-	$	121

Derivatives
Commodity contracts	$	69	$	60	$	-	$	-	$	2	$	5	$	2
Interest rate contracts		2		-		-		-		-		-
Total Derivatives	$	71	$	60	$	-	$	-	$	2	$	5	$	2

Total assets(1)	$	1,967	$	1,140	$	73	$	122	$	289	$	133	$	197

Liabilities

Derivatives
Commodity contracts	$	296	$	296	$	-	$	-	$	-	$	-	$	-
Interest rate contracts		5		-		-		-		-		-
Total Derivatives	$	301	$	296	$	-	$	-	$	-	$	-	$	-

Total liabilities	$	301	$	296	$	-	$	-	$	-	$	-	$	-

	Level 3
Assets		FirstEnergy		FES		TE		OE		JCP&L		Met-Ed		Penelec

Derivatives – NUG contracts(2)	$	148	$	-	$	-	$	-	$	6	$	137	$	5

Liabilities

Derivatives – NUG contracts(2)	$	738	$	-	$	-	$	-	$	400	$	167	$	171

(1)

Excludes $11 million of receivables, payables and accrued income.

(2) NUG contracts are subject to regulatory accounting and do not impact earnings.

	Recurring Fair Value Measures as of December 31, 2009
	Level 1
Assets		FirstEnergy		FES		TE		OE		JCP&L		Met-Ed		Penelec

Nuclear Decommissioning Trust Investments
Equity securities - consumer products	$	130	$	-	$	-	$	-	$	38	$	59	$	33
Equity securities - technology		57		-		-		-		17		26		14
Equity securities - utilities & energy		59		-		-		-		17		27		15
Equity securities - financial		39		-		-		-		12		17		10
Equity securities - other		9		-		-		-		3		4		2
Total nuclear decommissioning trust investments(1)	$	294	$	-	$	-	$	-	$	87	$	133	$	74
Total assets	$	294	$	-	$	-	$	-	$	87	$	133	$	74

Liabilities

Derivatives – commodity contracts	$	11	$	11	$	-	$	-	$	-	$	-	$	-
Total liabilities	$	11	$	11	$	-	$	-	$	-	$	-	$	-

	Level 2
Assets		FirstEnergy		FES		TE		OE		JCP&L		Met-Ed		Penelec

Nuclear Decommissioning Trust Investments
Debt securities issued by the U.S. government	$	558	$	306	$	72	$	118	$	23	$	30	$	9
Debt securities issued by states of the U.S.		188		15		-		-		41		82		50
Debt securities issued by foreign governments		279		279		-		-		-		-		-
Corporate debt securities		484		443		-		-		15		20		6
Other		35		29		-		2		1		2		1
Total nuclear decommissioning trust investments	$	1,544	$	1,072	$	72	$	120	$	80	$	134	$	66

Rabbi Trust Investments
Equity securities - financial	$	1	$	-	$	-	$	-	$	-	$	-	$	-
Other		9		-		-		-		-		-		-
Total rabbi trust investments	$	10	$	-	$	-	$	-	$	-	$	-	$	-

Nuclear Fuel Disposal Trust Investments
Debt securities issued by states of the U.S.	$	189	$	-	$	-	$	-	$	189	$	-	$	-
Other		11		-		-		-		11		-		-
Total nuclear fuel disposal trust investments	$	200	$	-	$	-	$	-	$	200	$	-	$	-

NUG Trust Investments
Debt securities issued by states of the U.S.	$	101	$	-	$	-	$	-	$	-	$	-	$	101
Other		19		-		-		-		-		-		19
Total NUG trust investments	$	120	$	-	$	-	$	-	$	-	$	-	$	120

Derivatives – commodity contracts	$	34	$	15	$	-	$	-	$	5	$	9	$	5
Other		1		-		-		-		-		-		-
Total assets(1)	$	1,909	$	1,087	$	72	$	120	$	285	$	143	$	191

Liabilities

Derivatives – commodity contracts	$	224	$	224	$	-	$	-	$	-	$	-	$	-
Total Liabilities	$	224	$	224	$	-	$	-	$	-	$	-	$	-

(1)

Excludes $21 million of receivables, payables and accrued income.

	Level 3
Assets		FirstEnergy		FES		TE		OE		JCP&L		Met-Ed		Penelec

Derivatives – NUG contracts(2)	$	200	$	-	$	-	$	-	$	9	$	176	$	15

Liabilities

Derivatives – NUG contracts(2)	$	643	$	-	$	-	$	-	$	399	$	143	$	101

(2) NUG contracts are subject to regulatory accounting and do not impact earnings.

The determination of the above fair value measures takes into consideration various factors. 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 months ended March 31, 2010 and 2009 (in millions):

	FirstEnergy			JCP&L			Met-Ed			Penelec
Balance as of January 1, 2010	$	(444	)	$	(391	)	$	33		$	(86	)
Settlements(1)		78			40			17			21
Unrealized losses(1)		(224	)		(43	)		(80	)		(101	)
Balance as of March 31, 2010	$	(590	)	$	(394	)	$	(30	)	$	(166	)

Balance as of January 1, 2009	$	(332	)	$	(518	)	$	150		$	36
Settlements(1)		83			45			17			21
Unrealized gains(1)		(227	)		(45	)		(91	)		(91	)
Balance as of March 31, 2009	$	(476	)	$	(518	)	$	76		$	(34	)

(1) Changes in fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.

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 ~~investing~~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. The Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practices.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet those criteria are accounted for at cost under the accrual method of accounting. The changes in the fair value of derivative instruments that do not meet the normal purchase and normal sales criteria are included in purchased power, other expense, unrealized gain (loss) on derivative hedges in other comprehensive income (loss), or as part of the value of the hedged item. 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 FirstEnergy’s consolidated financial position (assets, liabilities and equity) or cash f lows as of March 31, 2010. Based on derivative contracts held as of March 31, 2010, an adverse 10% change in commodity prices would decrease net income by approximately $4 million during the next 12 months. A hypothetical 10% increase in the interest rates associated with variable-rate debt would decrease net income by approximately $2 million for the three months ended March 31, 2010.

Cash Flow Hedges

FirstEnergy used 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 were 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~~three months of 2010, FirstEnergy terminated forward swaps with a notional value of $100 million. The termination of the forward starting swap agreements did not materially impact FirstEnergy’s net income and no forward starting swap agreements were outstanding as of March 31, 2010.

The table below provides the activity of AOCL related to interest rate cash flow hedges as of March 31, 2010 and 2009, ~~decreased by $432~~which is inclusive of changes in fair value of interest rate cash flow hedges and the reclassification from AOCL into results of operations.

		Three Months Ended
		March 31
		2010			2009
		(In millions)
Effective Portion
	Loss Recognized in AOCL	$	-		$	(2	)
	Reclassifications from AOCL into Interest Expense		(3	)		(5	)

Total unamortized losses included in AOCL associated with prior interest rate cash flow hedges totaled $101 million ($63 million net of tax) as of March 31, 2010. Based on current estimates, approximately $11 million will be amortized to interest expense during the next twelve months.

Fair Value Hedges

FirstEnergy uses fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. As of March 31, 2010, the debt underlying the $950 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.5%, which the swaps have converted to a current weighted average variable rate of 3.74%. The gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attri butable to the hedged risk are recognized in earnings. As of March 31, 2010, the gain included in interest expense related to interest rate swaps totaled $1 million and there was no impact on the results of operations as a result of ineffectiveness from fair value hedges.

The following tables summarize the fair value of interest rate swaps in FirstEnergy’s Consolidated Balance Sheets:

		Derivative Assets						Derivative Liabilities
		Fair Value						Fair Value
		March 31		December 31				March 31		December 31
		2010		2009				2010		2009
Fair Value Hedges		(In millions)			Fair Value Hedges			(In millions)
Interest Rate Swaps					Interest Rate Swaps
Noncurrent Assets	$	2	$	-		Noncurrent Assets	$	5	$	-
	$	2	$	-			$	5	$	-

On April 29, 2010, April 30, 2010 and May 3, 2010, FirstEnergy executed multiple fixed-for-floating interest rate swap agreements with combined notional amounts of $1.3 billion, $300 million and $600 million, respectively, to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. This is consistent with FirstEnergy’s risk management policy and its 2010 financial plan. These derivatives will be treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of May 3, 2010, the debt underlying the $2.2 billion outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 6%, which the swaps have converted to a current weighted avera ge variable rate of 3.4%.

Commodity Derivatives

The following tables summarize the fair value of commodity derivatives in FirstEnergy’s Consolidated Balance Sheets:

Derivative Assets					Derivative Liabilities
		Fair Value					Fair Value
		March 31		December 31			March 31		December 31
		2010		2009			2010		2009
Cash Flow Hedges		(In millions)			Cash Flow Hedges		(In millions)
Electricity Forwards					Electricity Forwards
Current Assets	$	39	$	3	Current Liabilities	$	39	$	7
Noncurrent Assets		19		11	Noncurrent Liabilities		26		12
Natural Gas Futures					Natural Gas Futures
Current Assets		-		-	Current Liabilities		7		9
Noncurrent Assets		-		-	Noncurrent Liabilities		-		-
Other					Other
Current Assets		-		-	Current Liabilities		1		2
Noncurrent Assets		-		-	Noncurrent Liabilities		-		-
	$	58	$	14		$	73	$	30


Derivative Assets					Derivative Liabilities
		Fair Value					Fair Value
		March 31 2010		December 31 2009			March 31 2010		December 31 2009
Economic Hedges		(In millions)			Economic Hedges		(In millions)
NUG Contracts					NUG Contracts
Power Purchase					Power Purchase
Contract Asset	$	148	$	200	Contract Liability	$	738	$	643
Other					Other
Current Assets		1		-	Current Liabilities		139		106
Noncurrent Assets		10		19	Noncurrent Liabilities		92		97
	$	159	$	219		$	969	$	846
Total Commodity Derivatives	$	217	$	233	Total Commodity Derivatives	$	1,042	$	876

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 coal transportation contracts. Derivative instruments are not used in quantities greater than forecasted needs. The following table summarizes the volume of FirstEnergy’s outstanding derivative transactions as of March 31, 2010:

	Purchases		Sales		Net		Units
	(In thousands)
Electricity Forwards		19,104		(11,924)		7,180	MWH
Heating Oil Futures		3,360		-		3,360	Gallons
Natural Gas Futures		2,000		(1,500)		500	mmBtu

The effect of derivative instruments on the consolidated statements of income and comprehensive income for the three months ended March 31, 2010 and 2009, for instruments designated in cash flow hedging relationships and not in hedging relationships, respectively, are summarized in the following tables:

		Three Months Ended March 31,
Derivatives in Cash Flow Hedging Relationships		Electricity			Natural Gas			Heating Oil
		Forwards			Futures			Futures			Total
2010		(in millions)
Gain (Loss) Recognized in AOCL (Effective Portion)	$	(5	)	$	(1	)	$	-		$	(6	)
Effective Gain (Loss) Reclassified to:(1)
Purchased Power Expense		(4	)		-			-			(4	)
Fuel Expense		-			(3	)		(1	)		(4	)

2009
Gain (Loss) Recognized in AOCL (Effective Portion)	$	(2	)	$	(7	)	$	(1	)	$	(10	)
Effective Gain (Loss) Reclassified to:(1)
Purchased Power Expense		(18	)		-			-			(18	)
Fuel Expense		-			-			(4	)		(4	)

(1) The ineffective portion was immaterial.

		Three Months Ended March 31,
Derivatives Not in Hedging Relationships			NUG
			Contracts			Other			Total
2010			(In millions)
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense		$	-		$	(52	)	$	(52	)
Regulatory Assets(2)			(224	)		-			(224	)
		$	(224	)	$	(52	)	$	(276	)
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		$	-		$	(25	)	$	(25	)
Regulatory Assets(2)			(78	)		9			(69	)
		$	(78	)	$	(16	)	$	(94	)
2009
Unrealized Gain (Loss) Recognized in:
Regulatory Assets(2)		$	(227	)	$	-		$	(227	)

Realized Gain (Loss) Reclassified to:
Fuel Expense(1)		$	-		$	(1	)	$	(1	)
Regulatory Assets(2)			(83	)		10			(73	)
		$	(83	)	$	9		$	(74	)

(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 $14 million ($9 million net of tax) as of March 31, 2010, as compared to $32 million ($19 million net of tax) as of March 31, 2009. The net of tax change resulted from a net $5 million increase related to current hedging activity and a $5 million decrease due to net hedge losses reclassified to earnings during the first ~~six~~quarter of 2010. Based on current estimates, approximately $5 million (after tax) of the net deferred losses on derivative instruments in AOCL as of March 31, 2010 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.

Many of FirstEnergy’s commodity derivatives contain credit risk features. As of March 31, 2010, FirstEnergy posted $225 million of collateral related to net liability positions and held no counterparties’ funds related to asset positions. The collateral FirstEnergy has posted relates to both derivative and non-derivative contracts. FirstEnergy’s largest derivative counterparties fully collateralize all derivative transactions. Certain commodity derivative contracts include credit risk-related contingent features that would require FirstEnergy to post additional collateral if the credit rating for its debt were to fall below investment grade. The aggregate fair value of derivative instruments with credit risk-related contingent features that are in a liability position on March 31, 2010 was $245 million, for which $225 million in collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post $40 million of additional collateral related to commodity derivatives.

5. PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy’s net pension and OPEB expenses (benefits) for the three months ended March 31, 2010 and 2009 were $24 million and $43 million, respectively. The components of FirstEnergy's net pension and other postretirement benefit costs (including amounts capitalized) for the three months ended March 31, 2010 and 2009, consisted of the following:

	Three Months Ended
	March 31
Pension Benefits	2010			2009
	(In millions)
Service cost	$	25		$	22
Interest cost		78			80
Expected return on plan assets		(90	)		(81	)
Amortization of prior service cost		3			3
Recognized net actuarial loss		47			42
Net periodic cost	$	63		$	66

	Three Months Ended
	March 31
Other Postretirement Benefits	2010			2009
	(In millions)
Service cost	$	2		$	5
Interest cost		11			20
Expected return on plan assets		(9	)		(9	)
Amortization of prior service cost		(48	)		(38	)
Recognized net actuarial loss		15			16
Net periodic credit	$	(29	)	$	(6	)

Pension and other postretirement benefit obligations are allocated to FirstEnergy's subsidiaries employing the plan participants. The net periodic pension costs and net periodic other postretirement benefit costs (including amounts capitalized) recognized by FES and each of the Utilities for the three months ended March 31, 2010 and 2009 were as follows:

	Three Months Ended
	March 31
Pension Benefit Cost	2010		2009
	(In millions)
FES	$	22	$	18
OE		6		7
CEI		5		5
TE		2		2
JCP&L		6		9
Met-Ed		2		6
Penelec		5		4
Other FirstEnergy subsidiaries		15		15
	$	63	$	66

	Three Months Ended
	March 31
Other Postretirement Benefit Cost (Credit)	2010			2009
	(In millions)
FES	$	(7	)	$	(1	)
OE		(6	)		(2	)
CEI		(1	)		1
TE		(1	)		1
JCP&L		(2	)		(1	)
Met-Ed		(2	)		(1	)
Penelec		(2	)		-
Other FirstEnergy subsidiaries		(8	)		(3	)
	$	(29	)	$	(6	)

6. VARIABLE INTEREST ENTITIES

On January 1, 2010, FirstEnergy adopted the amendments to the consolidation topic addressing VIEs. This standard requires that FirstEnergy and its subsidiaries perform a qualitative analysis to determine whether a variable interest gives FirstEnergy or its subsidiaries a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. This standard also requires an ongoing reassessment of the primary beneficiary of a VIE and eliminates the quantitative approach previously re quired for determining whether an entity is the primary beneficiary. There was no impact to FirstEnergy or its subsidiaries as a result of the adoption of this standard.

FirstEnergy’s consolidated financial statements include the accounts of entities in which it has a controlling financial interest. 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 net losses of the noncontrolling interests ($6 million) and distributions to owners ($3 million).

FirstEnergy has financial control through disproportionate economics in its equity investments and loans to certain VIEs, which include FEV’s joint venture in the Signal Peak mining and coal transportation operations, the PNBV and Shippingport bond trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions, and wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station, of which $333 million was outstanding as of March 31, 2010. As a result, FirstEnergy consolidates these VIEs.

In order to evaluate contracts under the consolidation guidance, FirstEnergy aggregated contracts into two categories based on similar risk characteristics and significance as follows:

Power Purchase Agreements

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 20 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 two of these entities, neither JCP&L, nor 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 consolidation consideration for VIEs. JCP&L may hold variable interests in the remaining two entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. However, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.

Since JCP&L has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it incurs for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs related to the two contracts that may contain a variable interest were $65 million and $67 million for the three months ended March 31, 2010, and 2009, respectively.

Loss Contingencies

FirstEnergy has variable interests in certain sale-leaseback transactions. FirstEnergy concluded that it is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the arrangement.

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	$	1,372	$	1,195	$	177
OE	702		538		164
CEI(2)	702		69		633
TE(2)	702		385		317

(1)	The net present value of FirstEnergy's consolidated sale and leaseback operating lease commitments is $1.7 billion.

(2)

CEI and TE are jointly and severally liable for the maximum loss

amounts under certain sale-leaseback agreements.

7. INCOME TAXES

FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Accounting guidance 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. After reaching a tentative agreement with the IRS on a tax item at appeals related to the capitalization of certain costs, FirstEnergy reduced the amount of unrecognized tax benefits by $57 million, with a corresponding adjustment to accumulated deferred income taxes for this temporary tax item. There was no impact on FirstEnergy’s effective tax rate for this tax item for the first three 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~~2010. Upon completion of the ~~purchase of certain lessor equity interests in Beaver Valley Unit 2 and Perry, and~~federal tax examination for 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 assets2007 tax year in the first quarter of ~~2008.~~2009, FirstEnergy recognized $13 million i n tax benefits, which favorably affected FirstEnergy's effective tax rate.

~~During~~As of March 31, 2010, it is reasonably possible that approximately $107 million of the ~~second half~~unrecognized benefits may be resolved within the next twelve months, of ~~2009, capital requirements for property additions~~which approximately $12 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 ~~capital leases are~~losses recognized on the disposition of assets and various other tax items.

The Company recognizes 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 and the amount previously taken or expected to be ~~approximately $773 million, including approximately $176 million for nuclear fuel.~~taken on the tax return. 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 arrangementsincludes net interest and ~~funds raised~~penalties in the ~~capital markets.~~provision for income taxes. The reversal of accrued interest associated with the $57 million in recognized tax benefits in 2010 favorably affected FirstEnergy’s effective tax rate by $5 million in the first quarter of 2010. During the first three months of 2009, there were no material changes to the amount of interest accrued. The net amount of accumulated interest accrued as of March 31, 2010 was $20 million, as compared to $21 mil lion as of December 31, 2009.

~~FirstEnergy's capital spending~~As a result of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law on March 23, 2010 and March 30, 2010, respectively, beginning in 2013 the tax deduction available to FirstEnergy will be reduced to the extent that drug costs are reimbursed under the Medicare Part D retiree subsidy program. As retiree healthcare liabilities and related tax impacts are already reflected in FirstEnergy’s consolidated financial statements, the change resulted in a charge to FirstEnergy’s earnings in the first quarter of 2010 of approximately $12.6 million and a reduction in accumulated deferred tax assets associated with these subsidies. This change reflects the anticipated increase in income taxes that will occur as a result of the change in tax law.

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 ~~period 2009-2013~~years 2001-2003 in July 2004 and several items were under appeal. In the fourth quarter of 2009, these items were settled at appeals and sent to Joint Committee on Taxation for final review. The federal audits for years 2004-2006 were completed in the third quarter of 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 audit 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 areclose before December 2010. The 2009 tax year audit began in February 2009 and th e 2010 tax year began in February 2010. Neither audit is expected to ~~be reduced by approximately $1.0 billion~~close before December 2010. Management believes that adequate reserves have been recognized and ~~$131 million, respectively, as the nuclear fuel~~final settlement of these audits is ~~consumed.~~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. ~~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~~March 31, 2010, outstanding guarantees and other assurances ~~approximated $4.6~~aggregated approximately $4.0 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.~~

consisting primarily of parental guarantees ($1.0 billion), subsidiaries’ guarantees ($2.6 billion), surety bonds and LOCs ($0.4 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 ~~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~~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~~FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by othe r FirstEnergy assets. ~~FirstEnergy believes the~~The likelihood is remote that such parental guarantees ~~will~~of $0.3 billion (included in the $1.0 billion discussed above) as of March 31, 2010 would increase amounts otherwise ~~paid~~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 ~~to below investment grade~~ or a “material adverse event,” the immediate posting of cash collateral, provision of ana LOC or accelerated payments may be required of the subsidiary. On February 11, 2010, S&P issued a report lowering FirstEnergy’s and its subsidiaries’ credit ratings by one notch, while maintaining its stable outlook. As a result, FirstEnergy was required to post $46 million of collateral. Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries. As of ~~June 30, 2009, FirstEnergy’s~~March 31, 2010, FirstEnergy's maximum exposure under these collateral provisions was ~~$601~~$428 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~~consisting of $37 million due to “material adverse event” contractual clauses, $63 million due to an acceleration of payment or funding obligation, and $328 million due to a below investment grade credit rating that includes the $46 million related to the credit rating downgrade by S&P. 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 ~~the total potential~~this amount to ~~$700~~$656 million, consisting of ~~$49~~$38 million due to “material adverse event” contractual clauses, $63 million related to an acceleration of payment or funding obligation, and ~~$651~~$555 million due to a below investment grade credit rating.

Most of ~~FirstEnergy’s~~FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $77 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’ power portfolio as of ~~June 30, 2009,~~March 31, 2010, and forward prices as of that date, FES ~~had $179 million~~has posted collateral of ~~outstanding collateral payments.~~$270 million. Under a hypothetical adverse change in forward prices ~~(15% decrease~~(95% confidence level change in ~~the first 12 months and 20% decrease thereafter in prices)~~forward prices over a one year time horizon), FES would be required to post an additional ~~$73~~$168 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~~an amount ~~of approximately~~up to $500 ~~million, dated as of June 16, 2009,~~million. The Surplus Margin Guaranty is secured by an NGC FMB issued 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 these sale and leaseback operating lease commitments, net of trust investments is $1.7 billion as of June 30, 2009.

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

~~MARKET RISK INFORMATION~~

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

~~Commodity Price Risk~~(B)

FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FirstEnergy's derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs or regulatory liability for below-market costs. The change in the fair value of commodity derivative contracts related to energy production during the three months and six months ended 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)~~ENVIRONMENTAL MATTERS ~~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 derivative contracts held as of June 30, 2009, an adverse 10% change in commodity prices would decrease net income by approximately $4 million during the next 12 months.

~~Forward Starting Swap Agreements - Cash Flow Hedges~~

FirstEnergy utilizes forward starting swap agreements in order to hedge a portion of the consolidated interest rate risk associated with anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 2009 and 2010, and anticipated variable-rate, short-term debt. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury and LIBOR rates between the date of hedge inception and the date of the debt issuance. During the first six months of 2009, FirstEnergy terminated forward swaps with an aggregate notional value of $100 million. FirstEnergy paid $1.3 million in cash related to the terminations, $0.3 million of which was deemed ineffective and recognized in current period earnings. The remaining effective portion ($1 million) will be recognized over the terms of the associated future debt. As of June 30, 2009, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $200 million and an aggregate fair value of $(3) million.

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
)

~~Equity Price Risk~~

FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover certain employees. The plan provides defined benefits based on years of service and compensation levels. FirstEnergy also provides health care benefits, which include certain employee contributions, deductibles, and co-payments, upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. The benefit plan assets and obligations are remeasured annually using a December 31 measurement date. FirstEnergy’s other postretirement benefits 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 on behalf of plan participants. The remeasurement and plan amendment will result in a $48 million reduction in FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the 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 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 23.8% compared to an assumed 9% positive return. Based on assumed 7-7.5% discount rates, FirstEnergy's pre-tax net periodic pension and OPEB expense was $38 million in the second quarter of 2009.

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~~

~~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 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.~~

~~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 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 Reliability~~First~~ ~~Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst~~ ~~region. FirstEnergy actively participates in the NERC and ReliabilityFirst~~ ~~stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.~~

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

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

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.

~~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. Reliability~~First~~ ~~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.~~

~~Ohio~~

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. 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 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.

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.

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.

~~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~~

~~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.

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 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 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.

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

~~Environmental Matters~~

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 $808 million for the period 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 $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.

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~~pla nts 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~~$399 million for ~~2009-2012 (with $414 million expected to be spent in 2009).~~2010-2012.

3839

~~On May 22,~~In October 2007, ~~FirstEnergy~~PennFuture and ~~FGCO received a notice letter, required 60 days prior to the filing~~three of its members filed 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,limitations, in the ~~United States~~U.S. 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~~U.S. 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 three 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.~~representa tives. On October ~~14, 2008,~~16, 2009, a settlement reached with PennFuture and one of the three individual complainants was approved by the Court, ~~granted FGCO’s motion to consolidate discovery for all four complaints pending against~~which dismissed the ~~Bruce Mansfield Plant.~~claims of PennFuture and of the settling individual. The other two non-settling individuals are now represented by counsel handling the three cases filed in July 2008. FGCO believes ~~the~~those claims are without merit and intends to defend itself against the allegations made in ~~these~~those three 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.~~has completed.

OnIn 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~~PSD 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~~Amende d Complaint and Connecticut’s Complaint in February and September of 2009, respectively. The Court granted Met-Ed's motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties on ~~February 19, 2009. On~~statute of limitations grounds in order to allow the states to prove either that the application of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.

In January ~~14,~~ 2009, the EPA issued a NOV to Reliant alleging ~~new source review~~NSR 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~~NSR violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of the Keystone Station, and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter. On

In 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~~PSD 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~~In August 2009, the EPA ~~for information pursuant to Section 114(a)~~issued a Finding of Violation and NOV alleging violations of the CAA ~~for certain operating~~ and ~~maintenance information regarding~~Ohio regulations, including the ~~Eastlake, Lakeshore, Bay Shore~~PSD, NNSR, 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 regardingTitle V regulations at the Eastlake, Lakeshore, Bay Shore, and Ashtabula generating plants. The EPA’s NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. In September 2009, FGCO received an information request pursuant to Section 114(a) of the CAA requesting certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shore and Ashtabula generating plants. On November 3, 2009, FGCO received a letter providing notification that the EPA is evaluating whether certain scheduled maintenance at the Eastlake generati ng plant may constitute a major modification under the NSR provision of the CAA. On December 23, 2009, FGCO received another information request regarding emission projections for the Eastlake generating plant pursuant to Section 114(a) of the CAA. FGCO intends to ~~fully~~ comply with the CAA, including EPA’s information requests, but, at this time, is unable to predict the outcome of this matter. A June 2006 finding of violation and NOV in which EPA alleged CAA violations at the Bay Shore Generating Plant remains unresolved and FGCO is unable to predict the outcome of such matter.

OnIn 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.

3940

National Ambient Air Quality Standards

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~~U.S. 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.” OnIn September ~~24,~~ 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. OnIn 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~~Court ’s July 11, 2008 opinion. On July 10, 2009, the ~~United States~~U.S. 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.

~~Mercury~~Hazardous Air Pollutant 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~~U.S. 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 onin May ~~20,~~ 2008. OnIn October ~~17,~~ 2008, the EPA (and an industry group) petitioned the ~~United States~~U.S. 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~~On April 15, 2010, the EPA ~~is developing new~~entered into a consent decree requiring it to propose maximum achievable control technology (MACT) regulations for mercury ~~emission~~and other hazardous air pollutants by March 16, 2011, and to finalize the regulations by November 16, 2011. On April 29, 2010, the EPA issued proposed MACT regulations requirin g emissions reductions of mercury and other hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels such as the proposed Burger biomass repowering project. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards ~~for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend~~applicable to electric generating units. Depending on the action taken by the EPA and on how any future regulations are ultimately ~~implemented.~~implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’s operations may result.

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,~~December 23, 2009, the Supreme Court of Pennsylvania affirmed the Commonwealth Court of Pennsylvania ~~declared~~ruling that Pennsylvania’s mercury rule is “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant (FirstEnergy’s only Pennsylvania coal-fired power plant) until 2015, if at all.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries. The ~~United States~~U.S. signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the ~~United States~~U.S. Senate. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity 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~~the December 2009 U.N. Climate Change Conference in Copenhagen did not reach a ~~new~~consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement which recognized the scientific view that the increase in global ~~agreement~~temperature should be below two degrees Celsius, included a commitment by developed countries to ~~reduce GHG~~provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020, and established the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. Once they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia, and the United States, would commit to quantified economy-wide emissions ~~post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed~~targets from 2020, while developing countries, including Brazil, China, and India, would agree to ~~lead~~take mitigation actions, subject to ~~an agreement in 2009.~~their domestic measurement, reporting, and verification. 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. The Senate continues to consider a number of measures to regulate GHG emissions. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the ~~United States~~U.S. 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,~~In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. Also in September 2009, the EPA proposed new thresholds for GHG emissions that define when CAA permits under the NSR and Title V oper ating permits programs would be required. The EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. The EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit. In December 2009, the EPA released ~~a “Proposed Endangerment~~its final “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 toGHG increase the threat of climate change. ~~Although~~In April 2010, EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles requiring an estimated combined average emissions level of 250 grams of CO2 per mile in model year 2016 and clarified that GHG regulation under the ~~EPA’s proposed finding, if finalized, does~~CAA will not ~~establish emission requirements~~be triggered 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~~and other stationary sources until January 2, 2011, at the earliest.

On September 21, 2009, the U.S. Court of Appeals for the Second Circuit and on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit, reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. On February 6, 2010, the Fifth Circuit granted defendants’ petition for rehearing en banc and on April 30, 2010, the Fifth Circuit cancelled the en banc hearing. On March 5, 2010, the Second Circuit denied defendants’ petition for rehearing and rehearing en banc. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribu te to global warming and result in property damages. While FirstEnergy is not a party to either litigation, should the courts of appeals decisions be ~~expected~~affirmed or not subjected to ~~support the establishment~~further review, FirstEnergy and/or one or more of ~~future emission requirements by the EPA for stationary sources.~~its subsidiaries could be named in actions making similar allegations.

FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other ~~expenditures.~~expenditures or result in changes to its operations. 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~~U.S. 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~~rulemaki ng 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 U.S. 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. The EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. 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~~th e states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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

Regulation of Waste Disposal

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion ~~waste products,~~residuals, 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,~~residuals, 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.~~residuals. In December 2009, the EPA provided to FGCO the findings of its review of the Bruce Mansfield Plant’s coal combustion residuals managem ent practices. The EPA observed that the waste management structures and the Plant “appeared to be well maintained and in good working order” and recommended only that FGCO “seal and maintain all asphalt surfaces.” On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA issued a proposed rule that provides two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FGCO's future cost of compliance with any coal combustion ~~waste~~residuals 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 EPA or the states.

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,~~March 31, 2010, 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~~$101 million (JCP&a mp;L - $74 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy - $24 million) have been accrued through ~~June 30, 2009.~~March 31, 2010. Included in the total are accrued liabilities of approximately ~~$68~~$67 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~~(C) OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. 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.

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~~sufficie nt 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~~Plaintiffs filed their appellate brief ~~is due~~ on August 25, 2009, and JCP~~&L's~~&L filed an opposition brief ~~is due~~ on September 25, 2009. On or about October 13, 2009, Plaintiffs filed their reply brief in further support of their appeal of the trial court's decision decertifying the class. The Appellate Division heard oral argument on January 5, 2010, before a three-judge panel. JCP&L is awaiting the Court’s decision.

Litigation Relating to the Proposed Allegheny Energy Merger

In connection with the proposed merger (Note 14), purported shareholders of Allegheny Energy have filed putative shareholder class action and/or derivative lawsuits in Pennsylvania and ~~Plaintiffs' reply~~Maryland state courts, as well as in the U.S. District Court for the Western District of Pennsylvania, against Allegheny Energy and its directors and certain officers, referred to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. The lawsuits allege, among other things, that the Allegheny Energy directors breached their fiduciary duties by approving the merger agreement, and that Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The plaintiffs allege that the merger consideration is unfair, that other terms in the merger agreement including the termination fee and the non-solicitation provision s are unfair, that certain individual defendants are financially interested in the merger, and that Allegheny Energy has failed to disclose material information about the merger to its shareholders. Among other remedies, the plaintiffs seek to enjoin the merger and they have demanded jury trials. The Allegheny Energy defendants moved to consolidate the Maryland lawsuits and filed motions to dismiss and answers to each of the Maryland complaints. The court consolidated the Maryland lawsuits and an amended complaint has been filed. The Allegheny Energy defendants, FirstEnergy, and Merger Sub filed motions to dismiss the amended complaint on April 21, 2010. The Maryland court has set a hearing for argument on the motions to dismiss for June 3, 2010. By order dated April 26, 2010, the Maryland court certified a plaintiff class that consists of all holders of Allegheny Energy shares at any time from February 11, 2010 to the consummation of the proposed merger. The Pennsylvania state court has consolidat ed the lawsuits filed in that court. The Allegheny Energy defendants and FirstEnergy have moved to stay the Pennsylvania lawsuits and the plaintiff has moved for leave to take expedited discovery. The Pennsylvania state court will hear argument on both motions on May 27, 2010. By stipulation dated April 14, 2010, no response is due ~~on October 5, 2009.~~to the complaint filed in the U.S. District Court for the Western District of Pennsylvania until June 10, 2010. While FirstEnergy and Allegheny Energy believe the lawsuits are without merit and intend to defend vigorously against the claims, the outcome of any such litigation is inherently uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay the completion of the merger and result in substantial costs to FirstEnergy and Allegheny Energy. In accordance with its bylaws, Allegheny Energy will advance expenses to and, as necessary, indemnify all of its directors in connection with the foregoing proceedings. All applicable insur ance policies may not provide sufficient coverage for the claims under these lawsuits, and rights of indemnification with respect to these lawsuits will continue whether or not the merger is completed. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect FirstEnergy’s business, financial condition or results of operations.

Nuclear Plant Matters

~~Nuclear Plant Matters~~Davis Besse Control Rod Drive Mechanism Nozzles

~~In August 2007,~~During a planned refueling outage at Davis-Besse that began on February 28, 2010, FENOC ~~submitted an application to~~initially identified 16 of the 69 control rod drive mechanism (CRDM) nozzles that required modification. The Nuclear Regulatory Commission was notified of these findings, along with federal, state and local officials. The initial nozzle inspection process included ultrasonic (UT) testing and visual inspections. On March 18, 2010, the NRC sent a special inspection team to ~~renew~~Davis-Besse.

FENOC has begun a comprehensive investigation to determine the ~~operating licenses~~underlying cause for the ~~Beaver Valley~~cracking, and retained a contractor to make the necessary modifications. Modifications will be made using a proven industry method subject to NRC review. Further evaluation and testing identified 8 additional nozzles requiring modification. Additional testing will be conducted following the modification of each nozzle to ensure safe, reliable plant operations. The plant is expected to be ready for restart in July 2010.

On April 5, 2010, the Union of Concerned Scientists (UCS) requested that the NRC issue a Show Cause Order, or otherwise delay the restart of the Davis-Besse Nuclear 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,until such time that the NRC ~~issued the final Safety Evaluation Report (SER) supporting the renewed license for Beaver Valley Units 1~~determines that adequate protection standards have been met 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. FENOCreasonable assurance exists that these standards will continue to ~~work with~~be met after the plant’s operation is resumed. What actions, if any, the NRC ~~Staff as it completes its environmental and technical reviews of the license renewal application, and is scheduled~~takes in response 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~~this request have yet to be ~~extended until 2036 and 2047 for Units 1 and 2, respectively.~~determined.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of ~~June 30, 2009,~~obligations. As of March 31, 2010, FirstEnergy had approximately ~~$1.7~~$1.9 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 additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010. ~~As required by~~By a letter dated March 8, 2010, primarily as a result of the Beaver V alley Power Station operating license renewal, FENOC requested that the NRC reduce FirstEnergy ~~annually recalculates and adjusts the amount of its~~ parental guarantee ~~as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based~~to $15 million and notified the staff that it no longer planned to make the additional contributions into the trusts. FirstEnergy is awaiting the NRC’s decision on ~~market conditions. If~~ the ~~value~~proposed reduction 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 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 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.guarantee.

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.

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.~~parties participated in the federal court's mediation programs and held private settlement discussions. On April 14, 2010, the parties reached a tentative agreement on a settlement package that must be reviewed and approved by the court. JCP&L recognized a liability for the potential $16 million award in ~~2005. Post-judgment~~2005, which has been adjusted for post-judgment interest that began to accrue as of February 25, ~~2009,~~2009.

On February 16, 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the ~~liability will be adjusted accordingly.~~

reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. 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~~reduction in the ~~event of a strike.~~

~~On May 21, 2009, 517 Penelec employees, represented~~discount was approved by the ~~International Brotherhood~~PUCO. On March 18, 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of ~~Electrical Workers (IBEW) Local 459, elected~~jurisdiction of the court of common pleas. The court has not yet ruled on that motion to ~~strike. In response, on May 22, 2009, Penelec implemented its work-continuation plan~~dismiss. The named-defendant companies will continue 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.defend these claims including challenging any class certification.

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

~~NEW ACCOUNTING STANDARDS AND INTERPRETATIONS~~9. REGULATORY MATTERS

~~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. 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 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 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. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

~~SFAS 168 – “The~~ ~~FASB Accounting Standards Codification~~TM ~~and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162”~~(A) RELIABILITY INITIATIVES

In ~~June 2009,~~2005, Congress amended the ~~FASB issued SFAS 168, which recognizes~~FPA 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 Reliability~~FASB Accounting Standards Codification~~TMFirst ~~(Codification) as~~Corporation. All of FirstEnergy’s facilities are located within the ~~source of authoritative GAAP. It also recognizes that rules~~ReliabilityFirst region. FirstEnergy actively participates in the NERC and ~~interpretative releases~~ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the ~~SEC under federal securities laws are sources of authoritative GAAP for SEC registrants. The Codification supersedes all non-SEC accounting and reporting~~reliability 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 interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 6 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~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.

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~~

InFirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that the ~~first six months~~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 ~~2009, net income increased~~complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to ~~$468 million from $158 million~~the FPA 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 ~~same period in 2008. The increase in net income includes FGCO’s $252 million pre-tax gain from the sale~~imposition of ~~9% of~~financial penalties that could have a material adverse effect on 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 thefinancial condition, 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,operations 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~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of The Toledo Edison Company:~~

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of 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 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 distribution services. JCP&L also provides generation services to franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.

~~Results of Operations~~

Net income for the first 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.

~~Revenues~~flows.

In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the ~~first six months~~Midwest ISO 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 ~~2009, revenues decreased~~FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards. FirstEnergy’s MISO facilities are next due for the periodic audit by $147 million, or 9%, compared with the same period of 2008. Retail and 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.ReliabilityFirst later this year.

~~Retail generation revenues decreased due to lower retail generation KWH sales~~On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in ~~all sectors, partially offset by higher unit prices~~an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the ~~residential~~affected area losing power. Power was restored to most customers within a few hours and ~~commercial sectors resulting from~~to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the ~~BGS auctions effective June 1, 2008,~~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 ~~June~~to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation required 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. ~~Lower sales~~The NERC conducted on site interviews with personnel involved in responding to the ~~residential sector reflected milder weather in~~event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP~~&L’s service territory, while~~&L replied as requested on August 6, 2009. JCP&L is not able at this time to predict what actions, if any, that the ~~decrease in sales to~~NERC may take based on the ~~commercial sector was primarily due to an increase in the number of shopping customers. Industrial sales were lower as a result of weakened economic conditions.~~data submittals or interview results.

~~Wholesale generation revenues decreased $124 million in the first six months~~On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of ~~2009 due to lower market prices and a decrease in sales volume from NUG purchases~~NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays (out of approximately 20,000 reportable 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 ~~termination~~relays. ReliabilityFirst issued an Initial Notice of ~~a NUG contract in October 2008.~~

~~Changes in retail generation KWH sales~~Alleged Violation on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 200 9, and ~~revenues by customer class in the first six months of 2009 compared~~submitted it 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~~FERC for approval on August 19, 2009. FirstEnergy is not able at this time 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 )

predict what actions or penalties, if any, that Reliability~~Expenses~~First

~~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~~ will propose for this self-reported violation.

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~~

~~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.~~

*	~~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)~~(B) OHIO

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request.filing. On January 21, 2009, the PUCO granted the Ohio Companies’ application in part 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.~~matter. The PUCO has not yet issued a substantive Entry on Rehearing. 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,by the Ohio Companies ~~notified~~was approved by the PUCO ~~that they were withdrawing~~on December 19, 2008. The Ohio Companies thereafter withdrew and ~~terminating~~terminated the ESP ~~application in addition to continuing~~and continued their ~~current~~ rate plan then 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~~Januar y 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 riderwhich 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~~w rite-off approximately $216 million of its Extended RTC ~~balance,~~regulatory asset, 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~~con tained 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.

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 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 of its other committed sales, including its position in the Ohio auction, FES' total generation hedged as a percentage of forecasted output is expected to be 93% in 2009 and 76% in 2010.

SB221 also requires electric distribution utilities to implement energy efficiency ~~programs that~~programs. Under the provisions of SB221, the Ohio Companies are required to 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.~~2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional ~~seventy-five hundredths of one percent~~.75% reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies have filed an application with the PUCO seeking such amendments. On January 7, 2010, the PUCO amended the 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than t hree years. On March 10, 2010, the PUCO found that due to a change in PUCO rules subsequent to the filing of the Ohio Companies’ application, the Ohio Companies’ application seeking a reduction of the peak demand reduction requirements was moot. In its March 10, 2010, Entry the PUCO also found that the Ohio Companies peak demand reduction programs complied with PUCO rules.

The Ohio Companies are presently involved in collaborative efforts related to energy efficiency programs, including filing applications for approval of those programs with the PUCO, as well as other implementation efforts arising out of the Supplemental Stipulation. On December 15, 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The PUCO set the matter for a hearing that was completed on March 8, 2010, and all briefing was completed by April 12, 2010. On March 8, 2010, the Ohio Companies filed their 2009 Status Update Report with the PUCO in which they indicated compliance with the 2009 statutory energy efficiency and peak demand benchmarks as those benchmark s were amended as described above. Interested parties filed comments on the Report. The PUCO has yet to address these comments. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers.

In October 2009, the PUCO issued additional Entries modifying certain of its previous rules that set out the manner in which electric utilities, including the Ohio Companies, will be required to comply with benchmarks contained in SB221 related to the employment of alternative energy resources, energy efficiency/peak demand reduction programs as well as greenhouse gas reporting requirements and changes to long term forecast reporting requirements. Applications for rehearing filed in mid-November 2009 were granted on December 9, 2009 for the sole purpose of further consideration of the matters raised in those applications. The PUCO has not yet issued a substantive Entry on Rehearing. The rules implementing the requirements of SB221 went into effect on December 10, 2009.

Additionally under SB221, 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~~In August and October 2009, the Ohio Companies conducted RFPs to ~~address~~secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs will be used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On December 7, 2009, the Ohio Companies filed an application with the PUCO seeking a force majeure determination regarding the Ohio Companies’ compliance with ~~these requirements. Costs associated with compliance are recoverable from customers.~~

the 2009 solar energy resources benchmark, and seeking a reduction in the benchmark. On ~~June 17, 2009,~~March 10, 2010, the PUCO ~~modified rules~~found that ~~implement~~there was an insufficient quantity of solar energy resources reasonably available in the market and thus granted the Ohio Companies’ application seeking force majeure. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies’ acquired through their 2009 RFP processes, provided the Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2010, the Ohio Companies and FES (due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy ~~portfolio standards created by~~requirements in SB221 ~~including~~for 2009. FES also applied for a force majeure determination from the ~~incorporation~~PUCO regarding a portion of ~~energy efficiency requirements, long-term forecast and greenhouse gas reporting and CO~~2 ~~control planning. The PUCO filed the rules~~their compliance with the ~~Joint Committee~~2009 solar energy resource benchmark, which application is still pending.

On October 20, 2009, the Ohio Companies filed an MRO to procure electric generation service for the period beginning June 1, 2011. The proposed MRO would establish a CBP to secure generation supply for customers who do not shop with an alternative supplier and would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on ~~Agency Rule Review~~a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility and supplier risk and encourage bidder participation. A technical conference was held on ~~July 7,~~October 29, 2009. Hearings took place in December 2009 ~~after~~and the matter has been fully briefed. Pursuant to SB221, the PU CO has 90 days from the date of the application to determine whether the MRO meets certain statutory requirements. Although the Ohio Companies requested a PUCO determination by January 18, 2010, on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements are met, the Ohio Companies would be able to implement the MRO and conduct the CBP.

On March 23, 2010, the Ohio Companies filed an application for a new ESP, which ~~begins~~if approved by the PUCO, would go into effect on June 1, 2011 and conclude on May 31, 2014. Attached to the application was a ~~65-day review period.~~Stipulation and Recommendation signed by the Ohio Companies, the Staff of the PUCO, and an additional fourteen parties signing as Signatory Parties, with two additional parties agreeing not to oppose the adoption of the Stipulation. The material terms of the Stipulation include a CBP similar to the one used in May 2009 and the one proposed in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided by the Ohio Companies through a bilateral wholesale contract with FES; no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider D CR), to recover a return of, and on, capital investments in the delivery system. This Rider replaces the Delivery Service Improvement Rider (Rider DSI) which terminates by its own terms. The Ohio Companies also agree not to collect certain amounts associated with RTEP and ~~one other party filed applications for rehearing on the rules~~administrative costs associated with the move to PJM. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP also requests the resolution of current proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the move to PJM. The evidentiary hearing began on ~~July 17, 2009.~~April 20, 2010, at the PUCO. The Stipulation requested a decision by the PUCO by May 5, 2010. On April 28, 2010, the PUCO Chairman issued a statement that the PUCO will not issue a decision on May 5, 2010, and will take additional time to review the case record. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP.

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

On February 20, 2009, Met-Ed and Penelec ~~were~~filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designed to ~~replace~~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 proposed a staggered procurement schedule, which varies by customer class, through 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 eventuse of a ~~third party supplier default, the increased costs to~~descending clock auction. On August 12, 2009, Met-Ed and Penelec ~~could be material.~~filed a settlement agreement with the PPUC for the generation procurement plan covering the period January 1, 2011, through May 31, 2013, reflecting the settlement on all but two issues. The settlement plan proposes a staggered procurement schedule, which varies by customer class. On September 2, 2009, the ALJ issued a Recommended Decision (RD ) approving the settlement and adopted the Met-Ed and Penelec’s positions on two reserved issues. On November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two reserved issues. Generation procurement began in January 2010.

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~~for 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. 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. On August 11, 2009, the ALJ issued a Recommended Decision to the PPUC approving Met-Ed’s and Penelec’s TSCs as filed and dismissing all complaints. Exceptions by various interveners were filed and reply exceptions were filed by Met-Ed and Penelec. The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which denies the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directs Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructs Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. On March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of marginal transmission loss costs. By Order entered March 25, 2010, the PPUC granted the requested stay until December 31, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of Met-Ed and Penelec that they should prevail in the appeal and therefore expect to fully recover the approximately $199.7 million ($158.5 million for Met-Ed and $41.2 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On April 2, 2010, Met-Ed and Penelec filed a Response to the PPUC’s March 3, 2010 Order requesting approval of procedures to establish separate accounts to track all marginal transmission loss revenues and related interest and the use of those funds to mitigate future generation rate increases commencing January 1, 2011

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 subject to the outcome of the proceeding related to the 2008 TSC filing described above, 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~~PPU C’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~~would increase approximately 9.4% for the period June 2009 through May 2010.

~~On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which~~Act 129 became effective ~~on November 14,~~in 2008 ~~as Act 129 of 2008. Act 129~~and 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.~~

Among other things Act 129 ~~requires~~required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a ~~smart meter procurement and installation plan~~minimum of 4.5% 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.May 31, 2013. On July 1, 2009, Met-Ed, Penelec, and Penn filed ~~Energy Efficiency and Conservation~~EE&C Plans with the PPUC in accordance with Act 129. The Pennsylvania Companies submitted a supplemental filing on July 31, 2009, to revise the Total Resource Cost test items in the EE&C Plans pursuant to the PPUC’s June 23, 2009 Order. Following evidentiary hearings and further revisions to the EE&C Plans, the Pennsylvania Companies filed final plans and tariff revisions on February 5, 2010 consistent with the minor revisions required by the PPUC. The PPUC entered an Order on February 26, 2010 approving the final plans and the tariff rider with rates effective March 1, 2010.

Act 129 also required utilities to file by August 14, 2009 with the PPUC smart meter technology procurement and installation plan to provide for the installation of smart meter technology within 15 years. On August 14, 2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan. Consistent with the PPUC’s rules, this plan proposes a 24-month assessment period in which the Pennsylvania Companies will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs at approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. An Initial Decision was issued by the presiding ALJ on January 28, 2010. The ALJ’s Initial Decision approved the Smart Meter Plan as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; eliminating the provision of interest in the 1307(e) reconciliation; providing for the recovery of reasonable and prudent costs minus resulting savings from installation and use of smart meters; and reflecting that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. On April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision issued on January 28, 2010, and decided various issues regarding the Smart Meter Implementation Plan (SMIP) for the Pennsylvania Companies. An order consistent with Chairman Cawley’s Motion is anticipated t o be entered in the near future, in which event the Pennsylvania Companies will move forward with the Smart Meter Technology Procurement and Installation Plan.

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

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~~$59 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~~t ariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the ~~companies’~~Pennsylvania Companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings.

By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30-day comment period on whether “the Restructuring Settlement allows NUG over-collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.” In response to the Tentative Order, the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec filed reply comments on October 26, 2009. On November 5, 2009, the PPUC issued a Secretarial Letter allowing parties to file reply comments to Met-Ed and Penelec’s rep ly comments by November 16, 2009, and reply comments were filed by the Office of Consumer Advocate, ARIPPA, and the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance. Met-Ed and Penelec are awaiting further action by the PPUC.

On February 8, 2010, Penn filed with the PPUC ~~action~~a generation procurement plan covering the period June 1, 2011 through May 31, 2013. The 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 proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. A preliminary conference was held on March 26, 2010, and, among other things, established a procedural schedule. Evidentiary hearings are scheduled for June 15-16, 2010. The PPUC is required to issue an order on the ~~July 31, 2009 filings.~~

plan no later than November 8, 2010.

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

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, 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,~~March 31, 2010, the accumulated deferred cost balance totaled approximately ~~$149~~$55 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~~al so 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. On April 16, 2010, the BPU issued an order indefinitely suspending the requirement of New Jersey utilities to submit Utility Master Plans until such time as the status of the EMP has been made clear. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on ~~its~~their operations.

In support of ~~the~~former New Jersey ~~Governor's~~Governor Corzine'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~~In addition, 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. The project relating to expansion of the existing demand response programs was approved by the NJBPU on August 19, 2009, and implementation began in 2009. Approval for the project related to energy efficiency programs intended to complement those currently being offered was denied by the NJBPU on December 1, 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal.

On February 11, 2010, S&P downgraded the senior unsecured debt of FirstEnergy Corp. to BB+. As a result, pursuant to the requirements of a pre-existing NJBPU order, JCP&L filed, on February 17, a plan addressing the mitigation of any effect of the downgrade and which provided an assessment of present and future liquidity necessary to assure JCP&L’s continued payment to BGS suppliers. The NJBPU subsequently held a public hearing to review the plan and available options. On March 17, 2010, the NJBPU determined that JCP&L demonstrated that it has ample resources available to continue uninterrupted payments to BGS suppliers and that there are no concerns with JCP&L's liquidity and therefore no further action is required.

(E) FERC ~~Matters~~ ~~(Applicable to FES and each of the Utilities)~~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~~subj ect 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. On October 29, 2009, March 17, 2010 and April 8, 2010, FirstEnergy, filed additional settlement agreements with FERC to resolve outstanding claims with various parties. FirstEnergy is actively pursuing settlement agreements with other parties to the case. On December 8, 2009, certain parties sought a writ of mandam us from the DC Circuit Court of Appeals directing FERC to issue an order on the Initial Decision. The Court agreed to hold this matter in abeyance based upon FERC’s representation to use good faith efforts to issue a substantive ruling on the initial decision no later than May 27, 2010. If FERC fails to act, the case will be submitted for briefing in June. The outcome of this matter cannot be predicted.

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 on the content of the compliance filings 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,~~zone s, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order (Opinion 494) 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~~rea sonable cost allocation methodology for inclusion in PJM’s tariff.

~~On May 18, 2007, certain parties filed for rehearing of the~~The FERC’s April 19, 2007 ~~order. On January 31, 2008, the requests~~order and a related order denying a request 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.

~~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,~~Circuit, which issued a decision on ~~behalf~~August 6, 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a postage-stamp basis and, based on this finding, remanded the rate design issue back to FERC. A request for rehearing and rehearing en banc by two companies was denied by the Seventh Circuit on October 20, 2009.

In an order dated January 21, 2010, FERC set the matter for “paper hearings” – meaning that FERC called for parties to submit comments or written testimony pursuant to the schedule described in the order. FERC identified nine separate issues for comments, and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments within 45 days, and reply comments 30 days later. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. Interested parties may file responsive comments or studies by May 28, 2010. Reply comments are due by June 28, 2010.

RTO Consolidation

On August 17, 2009, FirstEnergy filed an application with the FERC requesting to consolidate its ~~affiliated operating utility companies,~~transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The consolidation would make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s transmission assets in Pennsylvania and all of the transmission assets in New Jersey already operate as a part of PJM. Key elements of the filing include a Fixed Resource Requirement Plan (FRR Plan) that describes the means whereby capacity will be procured and administered as necessary to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years; and also a request that ATSI’s transmission customers be excused f rom the costs for regional transmission projects that were approved through PJM’s RTEP process prior to ATSI’s entry into PJM (legacy RTEP costs). The integration is expected to be complete on June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for the Ohio Companies. To ensure a definitive ruling at the same time the FERC rules on its request to integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a ~~motion~~related complaint with the FERC on the issue of exempting the ATSI footprint from the legacy RTEP costs.

On September 4, 2009, the PUCO opened a case to ~~intervene~~take comments from Ohio’s stakeholders regarding the RTO consolidation. FirstEnergy filed extensive comments in the PUCO case on September 25, 2009, and reply comments on October 13, 2009, and attended a public meeting on September 15, 2009 to answer questions regarding the RTO consolidation. Several parties have intervened in the regulatory dockets at the FERC and at the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including an exit fee to MISO, integration costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO.

On December 17, 2009, FERC issued an order approving, subject to certain future compliance filings, ATSI’s move to PJM. FirstEnergy’s request to be exempted from legacy RTEP costs was rejected and its complaint dismissed.

On December 17, 2009, ATSI executed the PJM Consolidated Transmission Owners Agreement. On December 18, 2009, the Ohio Companies and Penn executed the PJM Operating Agreement and the PJM Reliability Assurance Agreement. Execution of these agreements committed ATSI and the Ohio Companies and Penn’s load to moving into PJM on the schedule described in the application and approved in the FERC Order (June 1, 2011).

On January 15, 2010, the Ohio Companies and Penn submitted a compliance filing describing the process whereby ATSI-zone load serving entities (LSEs) can “opt out” of the Ohio Companies' and Penn's FRR Plan for the 2011-12 and 2012-13 delivery years. On January 16, 2010, FirstEnergy filed for clarification or rehearing of certain issues associated with implementing the FRR auctions on the proposed schedule. On January 19, 2010, FirstEnergy filed for rehearing of FERC’s decision to impose the legacy RTEP costs on ATSI’s transmission customers. Also on January 19, 2010, several parties, including the PUCO and the OCC asked for rehearing of parts of FERC’s order. None of the rehearing parties asked FERC to rescind authorization for ATSI to enter PJM. Instead, parties focused on questions of cost and cost allocation or on alleged errors in implementing the move. On February 3, 2010, FirstEnergy filed an answer to the January 19, 2010 rehearing requests of other parties. On February 16, 2010, FirstEnergy submitted a second compliance filing to FERC; the filing describes communications protocols and performance deficiency penalties for capacity suppliers that are taken in FRR auctions.

On March 10, 2010, FERC granted FirstEnergy’s request for expedited hearing on the conduct of the FRR auctions. The Ohio Companies and Penn obtained their PJM capacity requirements for the 2011 and 2012 delivery years in the FRR auctions conducted March 15-19, 2010. The PJM market monitor certified the FRR auction results on March ~~10, 2009.~~25, 2010, and the auction results were released by PJM on March 26, 2010. On March 29, 2010, the Ohio Companies and Penn signed agreements with all winning suppliers. In May 2010, the Ohio Companies and Penn’s load will be included in the PJM Base Residual Auction for the delivery year beginning 2013. FirstEnergy and unaffiliated generation and loads in the ATSI footprint are also expected to participate in the Base Residual Auction. FirstEnergy expects to integrate into PJM effective June 1, 2011.

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.~~FPA. 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~~F irstEnergy 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~~It 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~~and 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.~~Order.

MISO ~~Resource Adequacy Proposal~~Complaints Versus PJM

On March 9, 2010, MISO ~~made a filing on December 28, 2007~~filed two complaints against PJM with FERC under Sections 206, 306, and 309 of the FPA alleging violations of the MISO/PJM Joint Operating Agreement (JOA). In the first complaint, MISO alleged 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~~by failing to ~~become effective~~account for the ~~planning year beginning June 1, 2009. The filing would permit~~market flows from 34 PJM generators over the period from 2007-2009, PJM underpaid MISO by a total of roughly $75 million including interest. For the period from 2005-2007, MISO claimed an underpayment by PJM of at least $12 million plus interest. MISO also claimed that PJM failed 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 aremaintain required records 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 mechanismcalculate underbilling 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.2005-2007 billing.

In the second complaint, MISO alleged that PJM has refused to comply with provisions of the JOA requiring market-to-market dispatch since 2009, and is improperly demanding repayment of redispatch payments previously made to MISO.

~~100~~53

~~On October 20, 2008,~~PJM filed its answers to the ~~FERC issued three orders essentially permitting~~complaints on April 12, 2010, opposing the ~~MISO Resource Adequacy program to proceed~~relief sought by MISO. In addition, on April 12, 2010, PJM filed a complaint 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~~Section 206, 306, and 309 alleging that MISO is violating the JOA with PJM by initiating market-to-market coordination and financial settlements for substitute (proxy) reciprocal coordinated flowgates between MISO and PJM. PJM claims that the JOA does not permit MISO to initiate market-to-market settlements using proxy flowgates in lieu of ~~orders on rehearing and two~~designated reciprocal coordinated flowgates. This complaint addresses substantially the same issues as the second MISO complaint, in which MISO argues that the use of proxy flowgates is permitted by agreement of the ~~compliance filings occurred on February 19, 2009. No material changes were made~~RTOs and operating practice. Each party filed a complaint in order 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 filingensure their right to claim refunds, if any, if successful 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~~

~~On May 13-14, 2009, the Ohio Companies held an auction~~FirstEnergy has intervened in all three proceedings, and timely filed comments supporting MISO in its first complaint, relating to ~~secure generation supply for their PLR obligation. The results~~improper accounting of ~~the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate~~market flows resulting 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 tranchesunderpayments 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 SO~~2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $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 SO~~2 ~~reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO~~X reductions required by the 1990 Amendments are being achieved through combustion controls, 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 NO~~X ~~Transport Rule imposes uniform reductions of NO~~X ~~emissions (an approximate 85% reduction in utility plant NO~~X ~~emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NO~~X ~~emissions are contributing significantly to ozone levels in the eastern United States. FES believes its facilities are also complying with the NO~~X ~~budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.~~

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 SO~~2 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,~~2005-2009. 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.

~~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.

10. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

~~On May 16, 2008, FGCO received a request from~~In 2010, the ~~EPA for information pursuant to Section 114(a)~~FASB amended the Derivatives and Hedging Topic of the ~~CAA~~FASB Accounting Standards Codification to clarify the scope exception for ~~certain operating and maintenance information regarding~~embedded credit derivative features related to the ~~Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants~~transfer of credit risk in the form of subordination of one financial instrument to ~~allow the EPA~~another. The amendment addresses how to determine ~~whether these generating sources~~which embedded credit derivative features, including those in collateralized debt obligations and synthetic collateralized debt obligations, are ~~complying~~considered to be embedded derivatives that should not be analyzed under the Derivatives and Hedging Topic for potential bifurcation and separate accounting. The amendment is effective for the first fiscal quarter beginning after June 15, 2010. FirstEnergy does not expect this standard to have a material effect on its financial statements.

11. SEGMENT INFORMATION

Financial information for each of FirstEnergy’s reportable segments is presented in the following table. FES and the Utilities do not have separate reportable operating segments. With the completion of transition to a fully competitive generation market in Ohio in the fourth quarter of 2009, the former Ohio Transitional Generation Services segment was combined with the ~~NSR provisions of~~Energy Delivery Services segment, consistent with how management views the ~~CAA. On July 10, 2008, FGCO and the EPA entered into an Administrative Consent Order modifying that request and setting forth a schedule~~business. Disclosures for ~~FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA~~FirstEnergy’s operating segments for ~~information pursuant~~2009 have been reclassified 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 directedconform to the current ~~owner, Reliant Energy,~~presentation.

The energy delivery services segment transmits and distributes electricity through FirstEnergy’s eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR and default service requirements in Ohio, Pennsylvania and New Jersey. Its revenues are primarily derived from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to ~~allow~~retail customers who have not selected an alternative supplier (default service) in its Ohio, Pennsylvania and New Jersey franchise areas. Its results reflect the ~~EPA~~commodity costs of securing electric generation from FES and from non-affiliated power suppliers, the net PJM and MISO transmission expenses related to ~~determine whether these generating sources are complying with~~ the ~~NSR provisions~~deliver y of the ~~CAA. FirstEnergy intends to fully comply with~~respective generation loads, and the ~~EPA’s information request, but, at this time, is unable to predict the outcome~~deferral and amortization of ~~this matter.~~certain fuel costs.

~~National Ambient Air Quality Standards~~ ~~(Applicable~~The competitive energy services segment supplies electric power to ~~FES)~~

~~In March 2005,~~end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the ~~EPA finalized CAIR, covering a total~~PLR and default service requirements of ~~28 states (including Michigan, New Jersey,~~FirstEnergy's Ohio and ~~Pennsylvania)~~Pennsylvania utility subsidiaries and ~~the District of Columbia, based on proposed findings that air emissions from 28 eastern states~~competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and ~~the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/~~Michigan. This business segment owns or ~~the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NO~~Xleases and SO2 ~~emissions in two phases (Phase I in 2009 for NO~~X~~, 2010 for SO~~2 ~~and Phase II in 2015 for both NO~~X ~~and SO~~2~~), ultimately capping SO~~2 ~~emissions in affected states to 2.5 million tons annually and NO~~X 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 CAIRoperates 19 generating facilities with a ~~new rule consistent with~~net demonstrated capacity of 13,710 MWs and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the ~~Court’s July 11, 2008 opinion. On July 10, 2009, the United States Court~~related costs of ~~Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar~~electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MI SO to ~~CAIR, called the “NO~~X 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 responsedeliver energy to the ~~Court’s ruling.~~segment’s customers.

~~103~~54

The other segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment.

~~Mercury Emissions~~ ~~(Applicable to FES)~~

Segment Financial Information

		Energy			Competitive
		Delivery			Energy						Reconciling
Three Months Ended		Services			Services			Other			Adjustments			Consolidated
		(In millions)
March 31, 2010
External revenues		$	2,543		$	716		$	4		$	(31	)	$	3,232
Internal revenues			-			674			-			(607	)		67
	Total revenues		2,543			1,390			4			(638	)		3,299
Depreciation and amortization			325			66			13			1			405
Investment income (loss), net			25			1			-			(10	)		16
Net interest charges			123			33			(1	)		17			172
Income taxes			69			47			4			(9	)		111
Net income (loss)			114			76			(15	)		(26	)		149
Total assets			22,530			10,948			605			(5	)		34,078
Total goodwill			5,551			24			-			-			5,575
Property additions			166			323			3			16			508

March 31, 2009
External revenues		$	3,021		$	335		$	7		$	(29	)	$	3,334
Internal revenues			-			893			-			(893	)		-
	Total revenues		3,021			1,228			7			(922	)		3,334
Depreciation and amortization			427			64			1			3			495
Investment income (loss), net			30			(29	)		-			(12	)		(11	)
Net interest charges			109			18			1			38			166
Income taxes			(12	)		103			(17	)		(20	)		54
Net income			(18	)		155			17			(39	)		115
Total assets			23,005			9,925			632			(5	)		33,557
Total goodwill			5,550			24			-			-			5,574
Property additions			165			421			49			19			654


*	Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for
	sales of RECs by FES to the Ohio Companies that are retained in inventory.

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.

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

The condensed consolidating statements of income for the three-months ended March 31, 2010 and 2009, consolidating balance sheets as of March 31, 2010 and December ~~2000,~~31, 2009 and consolidating statements of cash flows for the ~~EPA announced it would proceed~~three months ended March 31, 2010 and 2009 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES' investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 ~~and NO~~X emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. 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 the2007 Bruce Mansfield ~~Plant (FES’ only Pennsylvania coal-fired power plant) until 2015, if at all.~~

~~Climate Change~~ ~~(Applicable to FES)~~

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activitiesUnit 1 sale 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.leaseback transac tion.

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.

~~On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO~~2 ~~emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO~~2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On 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.

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

~~104~~55

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended March 31, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)

REVENUES	$	1,367,025		$	568,364		$	426,320		$	(973,616	)	$	1,388,093

EXPENSES:
Fuel		5,097			280,863			42,261			-			328,221
Purchased power from affiliates		968,537			5,079			60,953			(973,616	)		60,953
Purchased power from non-affiliates		450,215			-			-			-			450,215
Other operating expenses		53,126			99,776			139,420			12,189			304,511
Provision for depreciation		790			26,527			36,910			(1,309	)		62,918
General taxes		5,498			14,600			6,648			-			26,746
Total expenses		1,483,263			426,845			286,192			(962,736	)		1,233,564

OPERATING INCOME (LOSS)		(116,238	)		141,519			140,128			(10,880	)		154,529

OTHER INCOME (EXPENSE):
Investment income		1,897			54			(1,234	)		-			717
Miscellaneous income (expense), including
net income from equity investees		166,373			(1,633	)		(101	)		(163,329	)		1,310
Interest expense to affiliates		(58	)		(1,812	)		(435	)		-			(2,305	)
Interest expense - other		(23,373	)		(26,506	)		(15,763	)		15,998			(49,644	)
Capitalized interest		100			16,333			3,257			-			19,690
Total other income (expense)		144,939			(13,564	)		(14,276	)		(147,331	)		(30,232	)

INCOME BEFORE INCOME TAXES		28,701			127,955			125,852			(158,211	)		124,297

INCOME TAXES (BENEFITS)		(51,225	)		48,043			45,013			2,540			44,371

NET INCOME	$	79,926		$	79,912		$	80,839		$	(160,751	)	$	79,926

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

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

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

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

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

OTHER INCOME (EXPENSE):
Investment income (loss)		732			31			(29,637	)		-			(28,874	)
Miscellaneous income (expense), including															��
net income from equity investees		119,781			(78	)		-			(117,192	)		2,511
Interest expense to affiliates		(34	)		(1,758	)		(1,187	)		-			(2,979	)
Interest expense - other		(2,520	)		(21,058	)		(15,168	)		16,219			(22,527	)
Capitalized interest		51			7,750			2,277			-			10,078
Total other income (expense)		118,010			(15,113	)		(43,715	)		(100,973	)		(41,791	)

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

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

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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of March 31, 2010	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	-	$	2	$	9	$	-		$	11
Receivables-
Customers		248,994		-		-		-			248,994
Associated companies		408,743		199,145		129,194		(376,278	)		360,804
Other		18,732		12,856		50,071		-			81,659
Notes receivable from associated companies		165,496		209,604		108,323		-			483,423
Materials and supplies, at average cost		16,698		327,011		215,042		-			558,751
Prepayments and other		147,780		8,234		4,654		-			160,668
		1,006,443		756,852		507,293		(376,278	)		1,894,310

PROPERTY, PLANT AND EQUIPMENT:
In service		91,365		5,473,440		5,189,224		(386,022	)		10,368,007
Less - Accumulated provision for depreciation		15,030		2,802,155		1,973,499		(172,820	)		4,617,864
		76,335		2,671,285		3,215,725		(213,202	)		5,750,143
Construction work in progress		7,836		2,110,754		479,040		-			2,597,630
		84,171		4,782,039		3,694,765		(213,202	)		8,347,773

INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,091,114		-			1,091,114
Investment in associated companies		4,637,194		-		-		(4,637,194	)		-
Other		957		7,367		201		-			8,525
		4,638,151		7,367		1,091,315		(4,637,194	)		1,099,639

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		88,618		379,772		-		(401,928	)		66,462
Goodwill		24,248		-		-		-			24,248
Customer intangibles		114,567		-		-		-			114,567
Property taxes		-		27,811		22,314		-			50,125
Unamortized sale and leaseback costs		-		29,968		-		60,835			90,803
Other		80,182		71,044		9,188		(50,920	)		109,494
		307,615		508,595		31,502		(392,013	)		455,699
	$	6,036,380	$	6,054,853	$	5,324,875	$	(5,618,687	)	$	11,797,421

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	745	$	696,416	$	922,663	$	(18,640	)	$	1,601,184
Short-term borrowings-
Other		100,000		-		-		-			100,000
Accounts payable-
Associated companies		325,118		194,950		190,103		(324,920	)		385,251
Other		116,942		153,515		-		-			270,457
Accrued taxes		7,719		72,449		48,798		(62,381	)		66,585
Other		213,488		105,682		27,798		46,544			393,512
		764,012		1,223,012		1,189,362		(359,397	)		2,816,989

CAPITALIZATION:
Common stockholder's equity		3,589,580		2,419,526		2,203,491		(4,623,017	)		3,589,580
Long-term debt and other long-term obligations		1,519,155		1,855,784		554,591		(1,269,330	)		2,660,200
		5,108,735		4,275,310		2,758,082		(5,892,347	)		6,249,780

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		984,440			984,440
Accumulated deferred income taxes		-		-		351,383		(351,383	)		-
Accumulated deferred investment tax credits		-		35,590		21,763		-			57,353
Asset retirement obligations		-		25,933		910,520		-			936,453
Retirement benefits		35,114		184,060		-		-			219,174
Property taxes		-		27,811		22,314		-			50,125
Lease market valuation liability		-		250,871		-		-			250,871
Other		128,519		32,266		71,451		-			232,236
		163,633		556,531		1,377,431		633,057			2,730,652
	$	6,036,380	$	6,054,853	$	5,324,875	$	(5,618,687	)	$	11,797,421

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of December 31, 2009	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	-	$	3	$	9	$	-		$	12
Receivables-
Customers		195,107		-		-		-			195,107
Associated companies		305,298		175,730		134,841		(297,308	)		318,561
Other		28,394		10,960		12,518		-			51,872
Notes receivable from associated companies		416,404		240,836		147,863		-			805,103
Materials and supplies, at average cost		17,265		307,079		215,197		-			539,541
Prepayments and other		80,025		18,356		9,401		-			107,782
		1,042,493		752,964		519,829		(297,308	)		2,017,978

PROPERTY, PLANT AND EQUIPMENT:
In service		90,474		5,478,346		5,174,835		(386,023	)		10,357,632
Less - Accumulated provision for depreciation		13,649		2,778,320		1,910,701		(171,512	)		4,531,158
		76,825		2,700,026		3,264,134		(214,511	)		5,826,474
Construction work in progress		6,032		2,049,078		368,336		-			2,423,446
		82,857		4,749,104		3,632,470		(214,511	)		8,249,920

INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,088,641		-			1,088,641
Investment in associated companies		4,477,602		-		-		(4,477,602	)		-
Other		1,137		21,127		202		-			22,466
		4,478,739		21,127		1,088,843		(4,477,602	)		1,111,107

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		93,379		381,849		-		(388,602	)		86,626
Goodwill		24,248		-		-		-			24,248
Customer intangibles		16,566		-		-		-			16,566
Property taxes		-		27,811		22,314		-			50,125
Unamortized sale and leaseback costs		-		16,454		-		56,099			72,553
Other		82,845		71,179		18,755		(51,114	)		121,665
		217,038		497,293		41,069		(383,617	)		371,783
	$	5,821,127	$	6,020,488	$	5,282,211	$	(5,373,038	)	$	11,750,788

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	736	$	646,402	$	922,429	$	(18,640	)	$	1,550,927
Short-term borrowings-
Associated companies		-		9,237		-		-			9,237
Other		100,000		-		-		-			100,000
Accounts payable-
Associated companies		261,788		170,446		295,045		(261,201	)		466,078
Other		51,722		193,641		-		-			245,363
Accrued taxes		44,213		61,055		22,777		(44,887	)		83,158
Other		173,015		132,314		16,734		36,994			359,057
		631,474		1,213,095		1,256,985		(287,734	)		2,813,820

CAPITALIZATION:
Common stockholder's equity		3,514,571		2,346,515		2,119,488		(4,466,003	)		3,514,571
Long-term debt and other long-term obligations		1,519,339		1,906,818		554,825		(1,269,330	)		2,711,652
		5,033,910		4,253,333		2,674,313		(5,735,333	)		6,226,223

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		992,869			992,869
Accumulated deferred income taxes		-		-		342,840		(342,840	)		-
Accumulated deferred investment tax credits		-		36,359		22,037		-			58,396
Asset retirement obligations		-		25,714		895,734		-			921,448
Retirement benefits		33,144		170,891		-		-			204,035
Property taxes		-		27,811		22,314		-			50,125
Lease market valuation liability		-		262,200		-		-			262,200
Other		122,599		31,085		67,988		-			221,672
		155,743		554,060		1,350,913		650,029			2,710,745
	$	5,821,127	$	6,020,488	$	5,282,211	$	(5,373,038	)	$	11,750,788

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Three Months Ended March 31, 2010	FES			FGCO			NGC			Eliminations		Consolidated
	(In thousands)

NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES	$	(147,718	)	$	40,130		$	98,692		$	-	$	(8,896	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt		(197	)		(1,081	)		-			-		(1,278	)
Short-term borrowings, net		-			(9,237	)		-			-		(9,237	)
Other		(453	)		(177	)		(101	)		-		(731	)
Net cash used for financing activities		(650	)		(10,495	)		(101	)		-		(11,246	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(2,103	)		(174,163	)		(125,337	)		-		(301,603	)
Proceeds from asset sales		-			114,272			-			-		114,272
Sales of investment securities held in trusts		-			-			272,094			-		272,094
Purchases of investment securities held in trusts		-			-			(284,888	)		-		(284,888	)
Loans from associated companies, net		250,908			31,232			39,540			-		321,680
Customer intangibles		(100,615	)		-			-			-		(100,615	)
Other		178			(977	)		-			-		(799	)
Net cash provided from (used for) investing activities		148,368			(29,636	)		(98,591	)		-		20,141

Net change in cash and cash equivalents		-			(1	)		-			-		(1	)
Cash and cash equivalents at beginning of period		-			3			9			-		12
Cash and cash equivalents at end of period	$	-		$	2		$	9		$	-	$	11

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

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


NET CASH PROVIDED FROM OPERATING ACTIVITIES	$	200,420		$	28,545		$	118,902		$	-	$	347,867

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			100,000			-			-		100,000
Short-term borrowings, net		98,881			88,308			434,105			-		621,294
Redemptions and Repayments-
Long-term debt		(1,189	)		(626	)		(334,101	)		-		(335,916	)
Net cash provided from financing activities		97,692			187,682			100,004			-		385,378

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(358	)		(198,631	)		(213,816	)		-		(412,805	)
Proceeds from asset sales		-			7,573			-			-		7,573
Sales of investment securities held in trusts		-			-			351,414			-		351,414
Purchases of investment securities held in trusts		-			-			(356,904	)		-		(356,904	)
Loans to associated companies, net		(297,641	)		(6,322	)		-			-		(303,963	)
Other		(113	)		(18,852	)		400			-		(18,565	)
Net cash used for investing activities		(298,112	)		(216,232	)		(218,906	)		-		(733,250	)

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

13. INTANGIBLE ASSETS

FES has acquired certain customer contract rights, which were capitalized as intangible assets. These rights allow FES to supply electric generation needs to customers and are being amortized ratably over the term of the related contracts. Net intangible assets of $114 million are included in other assets on the FirstEnergy Consolidated Balance Sheet as of March 31, 2010.

For the three months ended March 31, 2010, amortization expense was approximately $3 million.

14. PROPOSED MERGER WITH ALLEGHENY ENERGY, INC.

As previously disclosed, on February 10, 2010, FirstEnergy entered into an Agreement and Plan of Merger (Merger Agreement) with Element Merger Sub, Inc., a Maryland corporation and its wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into Allegheny Energy with Allegheny Energy continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy. Pursuant to the Merger Agreement, upon the closing of the merger, each issued and outstanding share of Allegheny Energy common stock, including grants of restricted common stock, will automatically be converted into the right to receive 0.667 of a share of common stock of FirstEnergy and Allegheny Energy stockho lders will own approximately 27% of the combined company. The Merger Agreement was unanimously approved by both companies’ Boards of Directors.

Pursuant to the Merger Agreement, completion of the merger is conditioned upon, among other things, shareholder approval of both companies, the SEC’s clearance of a registration statement registering the FirstEnergy common stock to be issued in connection with the merger, as well as expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the FERC, the Maryland Public Service Commission, PPUC, the Virginia State Corporation Commission and the West Virginia Public Service Commission. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny Energy, and further provides for the payment of fees and expenses upon termination under specified circumstances.

On March 23, 2010, FirstEnergy filed with the SEC a registration statement on Form S-4 containing a preliminary joint proxy statement/prospectus relating to the proposed merger (Registration Statement). After the Registration Statement has been declared effective by the SEC, FirstEnergy and Allegheny Energy expect to send the joint proxy statement/prospectus contained in the Registration Statement to their respective shareholders and each hold a special shareholder meeting to approve proposals related to the merger.

The companies expect to make their filing with the FERC under Section 203 of the FPA and the applications for clearance under HSR in May 2010. Applications for state regulatory approval in Pennsylvania, Maryland, West Virginia and Virginia are expected to be filed in the second quarter of 2010.

In connection with the proposed merger, during the first quarter of 2010, FirstEnergy recorded approximately $14.2 million ($9.6 million after tax) of expenses associated with merger transactions costs. These costs are expensed as incurred.

FirstEnergy and Allegheny Energy currently anticipate completing the merger in the first half of 2011. Although FirstEnergy and Allegheny Energy believe that they will receive the required authorizations, approvals and consents to complete the merger, there can be no assurance as to the timing of these authorizations, approvals and consents or as to FirstEnergy’s and Allegheny Energy’s ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to Allegheny Energy and FirstEnergy. Further information concerning the proposed merger is included in the Registration Statement filed by FirstEnergy with the SEC in conn ection with the merger.

Item 2. Management's Discussion and Analysis of Registrant and Subsidiaries

FIRSTENERGY CORP.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

~~Clean Water Act~~ ~~(Applicable~~Earnings available to ~~FES)~~FirstEnergy Corp. in the first quarter of 2010 were $155 million, or basic and diluted earnings of $0.51 per share of common stock, compared with $119 million, or basic and diluted earnings of $0.39 per share of common stock in the first quarter of 2009. The increase in earnings resulted principally from decreased regulatory charges and increased investment income, partially offset by derivative mark-to-market adjustments, and increased fuel and purchased power costs and net amortization of regulatory assets.

~~Various water quality regulations,~~

Change in Basic Earnings Per Share From Prior Year	2010

Basic Earnings Per Share – First Quarter 2009		$	0.39
Non-core asset sales/impairments - 2010	(0.02			)
Trust securities impairments	0.05
Regulatory charges – 2009	0.55
Regulatory charges – 2010	(0.08			)
Derivative mark-to-market adjustment - 2010	(0.11			)
Organizational restructuring - 2009	0.05
Merger transaction costs - 2010	(0.03			)
Income tax resolution - 2009	(0.04			)
Income tax charge from healthcare legislation - 2010	(0.04			)
Revenues	(0.07			)
Fuel and purchased power	(0.13			)
Transmission expense	0.10
Amortization of regulatory assets, net	(0.17			)
Investment income	0.01
Other expenses		0.05
Basic Earnings Per Share – First Quarter 2010		$	0.51

Financial Matters

Proposed Merger with Allegheny Energy, Inc.

On February 10, 2010, FirstEnergy entered into an Agreement and Plan of Merger (Merger Agreement) with Element Merger Sub. Inc., a Maryland corporation and its wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the ~~majority~~terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into Allegheny Energy with Allegheny Energy continuing as the surviving corporation and a wholly-owned subsidiary of ~~which are~~FirstEnergy. Pursuant to the ~~result~~Merger Agreement, upon the closing of the ~~federal Clean Water Act~~merger, each issued and ~~its amendments, apply~~outstanding share of Allegheny Energy common stock, including grants of restricted common stock, will automatically be converted into the right to ~~FES’ plants. In addition, Ohio, New Jersey~~receive 0.667 of a share of common stock of FirstEnergy and ~~Pennsylvania have water quality standards applicable to FES' operations. As provided~~Allegheny Energy stockholders will own approximately 27% of the combined company. Based on the closing stock prices for both companies on February 10, 2010, Allegheny Energy shareholders would receive a value of $27.65 per share, or $4.7 billion in the ~~Clean Water~~aggregate. FirstEnergy will also assume all outstanding Allegheny Energy debt. The price per share represents a premium of 31.6% to the closing stock price of Allegheny Energy on February 10, 2010, and a 22.3% premium to the average stock price of Allegheny over the last 60 days ending February 10, 2010.

In connection with the proposed merger, during the first quarter of 2010, FirstEnergy recorded approximately $14.2 million ($9.6 million after tax) of merger transactions costs. These costs are expensed as incurred.

Pursuant to the Merger Agreement, completion of the merger is conditioned upon, among other things, shareholder approval of both companies, the SEC’s clearance of a registration statement registering the FirstEnergy common stock to be issued in connection with the merger, as well as expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act ~~authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed~~of 1976 and approval by ~~a state. Ohio, New Jersey~~the FERC, the Maryland Public Service Commission, PPUC, the Virginia State Corporation Commission and ~~Pennsylvania have assumed such authority.~~the West Virginia Public Service Commission. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny Energy, and further provides for the payment of fees and expenses upon termination under specified circumstances.

On ~~September 7, 2004,~~March 23, 2010, FirstEnergy filed with the ~~EPA established new performance standards~~SEC a registration statement on Form S-4 containing a preliminary joint proxy statement/prospectus relating to the proposed merger (Registration Statement). After the Registration Statement has been declared effective by the SEC, FirstEnergy and Allegheny Energy expect to send the joint proxy statement/prospectus contained in the Registration Statement to their respective shareholders and each hold a special shareholder meeting to approve proposals related to the merger.

The companies expect to make their filing with the FERC under Section ~~316(b)~~203 of the ~~Clean Water Act~~FPA and the applications for ~~reducing impacts on fish~~clearance under the HSR in May 2010. Applications for state regulatory approval in Pennsylvania, Maryland, West Virginia and ~~shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions~~Virginia are expected to be filed in ~~impingement mortality (when aquatic organisms are pinned against screens or other parts~~the second quarter of ~~a cooling water intake system)~~2010.

FirstEnergy and ~~entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007,~~Allegheny Energy currently anticipate completing the ~~United States Court~~merger in the first half of ~~Appeals for~~2011. Although FirstEnergy and Allegheny Energy believe that they will receive the ~~Second Circuit remanded portions of~~required authorizations, approvals and consents to complete the ~~rulemaking dealing with impingement mortality and entrainment back~~merger, there can be no assurance as to the ~~EPA for further rulemaking~~timing of these authorizations, approvals and ~~eliminated~~consents or as to FirstEnergy’s and Allegheny Energy’s ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to Allegheny Energy and FirstEnergy. Further information concerning the ~~restoration option from~~proposed merger is included in the ~~EPA’s regulations. On July 9, 2007,~~Registration Statement filed by FirstEnergy with the ~~EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue~~SEC i n connection with 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.merger.

~~Regulation~~During the first quarter of ~~Waste Disposal~~ ~~(Applicable to FES~~2010, FirstEnergy recorded charges of approximately $9.2 million ($6.0 million after-tax) associated with sale of FGCO’s 340-MW Sumpter Plant and ~~each~~the termination of ~~the Utilities)~~gas drilling participation rights associated with certain previously owned Ohio properties.

Derivative mark-to-market adjustments

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. Includedcertain purchased power contracts increased expenses in the ~~total are accrued liabilities~~first quarter of 2010 by $51.9 million ($32.5 million after tax). From December 31, 2009 to March 31, 2010 forward around the clock electricity prices per MWH have declined 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~~14%.

~~Power Outages and Related Litigation~~ ~~(Applicable to JCP&L)~~Elimination of retiree prescription drug tax benefits

~~In July 1999,~~As a result of the ~~Mid-Atlantic States experienced~~Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law on March 23, 2010 and March 30, 2010, respectively, beginning in 2011 the tax deduction available to FirstEnergy will be reduced to the extent that drug costs are reimbursed under the Medicare Part D retiree subsidy program. During the first quarter of 2010, FirstEnergy recognized a ~~severe heat wave, which resulted in power outages throughout~~one-time adjustment of approximately $12.6 million to reduce the ~~service territories~~deferred tax asset associated with these subsidies.

Operational Matters

Davis Besse Refueling

On February 28, 2010, the Davis Besse Nuclear Plant (908-MW) began a refueling outage to exchange 76 of ~~many electric utilities, including JCP&L's territory. Two class action lawsuits (subsequently consolidated into a single proceeding)~~the 177 fuel assemblies and conduct numerous safety inspections. During the outage, it was determined that modifications were ~~filed in New Jersey Superior Court~~needed to 16 of the 69 control rod drive mechanism nozzles (CDRM) that penetrated the reactor vessel head. Further evaluation and testing identified 8 additional nozzles requiring modifications. Additional testing will be conducted following the modification of each nozzle to ensure safe, reliable plant operations. The plant is expected to be ready for restart in July, ~~1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages.~~2010.

PJM RTO Integration

From March 15-19, 2010, PJM conducted two competitive auctions FRR Integration Auctions on behalf of the Ohio Companies and Penn to secure electric capacity for delivery years June 1, 2011 through May 31, 2012, and June 1, 2012 through May 21, 2013. Monitoring Analytics, LLC, acting as the PJM Market Monitor, certified the auction results on March 26, 2010. In the 2011/2012 auction, 27 suppliers participated, and 12,583 MW of capacity cleared at a price of $108.89/MW-day. The 2012/2013 auction had 28 market participants, with 13,038 MW of capacity clearing at a price of $20.46/MW-day. On March 29, 2010, the Ohio Companies and Penn signed agreements with all winning suppliers.

~~105~~64

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.Regulatory Matters - Ohio

~~Nuclear Plant Matters~~ ~~(Applicable to FES)~~New Electric Security Plan

On March 23, 2010, the Ohio Companies filed a new ESP with the PUCO. The ESP was filed as a Stipulation and Recommendation and incorporated the substantial record developed in the Ohio Companies’ earlier filing for an MRO. The ESP is a three-year plan that would begin June 1, 2011, would provide for a CBP to procure generation supply for customers that choose not to shop with an alternative supplier with more certain rate levels for customers, timely recovery of PUCO-authorized charges, deferral of certain costs and promotes energy efficiency and economic development. The Ohio Companies have requested PUCO approval by May 5, 2010. On April 28, 2010, the PUCO Chairman issued a statement that the PUCO will not issue a decision on May 5, 2010, and will take additional time to review the case record. In ~~August 2007, FENOC submitted an application~~connection with the filing , FirstEnergy recorded approximately $39.5 million ($25.2 million after tax) of regulatory asset impairments and expenses related to the ~~NRC to renew~~ESP.

Regulatory Matters - Pennsylvania

Met-Ed and Penelec Transmission Service Charge

On March 3, 2010, Met-Ed and Penelec received an Order from the ~~operating licenses~~PPUC which denied the recovery of marginal transmission losses through the TSC rider for the ~~Beaver Valley Power Station (Units~~period June 1, 2007 through March 31, 2008 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 1instructed Met-Ed 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 continuePenelec to work with the ~~NRC Staff as it completes~~parties and file a petition to retain any over-collection, with interest, until 2011, when Met-Ed and Penelec’s generation rate caps expire. In response to the Order, on March 18, 2010, Met-Ed and Penelec requested that the PPUC grant a stay of its ~~environmental~~Order, with such stay being granted by the PPUC on March 25, 2010 until December 31, 2010, allowing for the continued collection of marginal losses subject to refund. On April 1, 2010, Met-Ed and ~~technical reviews~~Penelec filed with the Commonwealth Court of Pennsylvania a Petition for Review of the ~~license renewal application,~~PPUC’s Order disallowing the recovery of ma rginal transmission losses in the TSC. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and ~~is scheduled to obtain renewed licenses~~Penlec believe they should prevail on appeal and should recover marginal transmission losses 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~~period prior to January 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 additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010. As required by the NRC, 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 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 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.2011.

~~Other Legal Matters~~ ~~(Applicable to FES and each of the Utilities)~~FIRSTENERGY'S BUSINESS

~~There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FES' and the Utilities' normal~~FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through two core business ~~operations pending against them. The other potentially material items not otherwise discussed above are described below.~~segments (see Results of Operations).

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.

Energy Delivery Services transmits and distributes electricity through our eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR and default service requirements in Ohio, Pennsylvania and New Jersey. Its revenues are primarily derived from the delivery of electricity within our service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service) in its Ohio, Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES and from non-affiliated power suppliers, the net PJM and MISO transmission expenses related to the delivery of the respective generation loads, and the deferral and amortization of certain fuel costs.

Competitive Energy Services supplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the PLR and default service requirements of our Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns or leases and operates 19 generating facilities with a net demonstrated capacity of 13,710 MW and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs char ged by PJM and MISO to deliver energy to the segment’s customers.

~~106~~65

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 11 to the consolidated financial statements. Earnings available to FirstEnergy Corp. by major business segment were as follows:

	Three Months Ended
	March 31						Increase
	2010			2009			(Decrease)
	(In millions, except per share data)
Earnings By Business Segment:
Energy delivery services	$	114		$	(18	)	$	132
Competitive energy services		76			155			(79	)
Other and reconciling adjustments*		(35	)		(18	)		(17	)
Total	$	155		$	119		$	36

Basic Earnings Per Share	$	0.51		$	0.39		$	0.12
Diluted Earnings Per Share	$	0.51		$	0.39		$	0.12

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

~~The bargaining unit employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008.~~ ~~On July 24,~~Summary of Results of Operations – First Quarter 2010 Compared with First Quarter 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.~~

~~On May 21,~~Financial results for FirstEnergy's major business segments in the first quarter of 2010 and 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.were as follows:

		Energy			Competitive			Other and
		Delivery			Energy			Reconciling			FirstEnergy
First Quarter 2010 Financial Results		Services			Services			Adjustments			Consolidated
		(In millions)
Revenues:
	External
	Electric	$	2,398		$	669		$	-		$	3,067
	Other		145			47			(27	)		165
	Internal*		-			674			(607	)		67
Total Revenues			2,543			1,390			(634	)		3,299

Expenses:
	Fuel		-			337			(3	)		334
	Purchased power		1,395			450			(607	)		1,238
	Other operating expenses		380			347			(26	)		701
	Provision for depreciation		113			66			14			193
	Amortization of regulatory assets		212			-			-			212
	Deferral of new regulatory assets		-			-			-			-
	General taxes		162			35			8			205
Total Expenses			2,262			1,235			(614	)		2,883

Operating Income			281			155			(20	)		416
Other Income (Expense):
	Investment income		25			1			(10	)		16
	Interest expense		(124	)		(53	)		(36	)		(213	)
	Capitalized interest		1			20			20			41
Total Other Expense			(98	)		(32	)		(26	)		(156	)

Income Before Income Taxes			183			123			(46	)		260
Income taxes			69			47			(5	)		111
Net Income (Loss)			114			76			(41	)		149
Noncontrolling interest loss			-			-			(6	)		(6	)
Earnings available to FirstEnergy Corp.		$	114		$	76		$	(35	)	$	155

*	Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sale of RECs by FES to the Ohio Companies that are retained in inventory.

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 Codification~~TM ~~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 Codification~~TM (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~~66

	Energy			Competitive			Other and
	Delivery			Energy			Reconciling			FirstEnergy
First Quarter 2009 Financial Results	Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	2,861		$	280		$	-		$	3,141
Other		160			55			(22	)		193
Internal		-			893			(893	)		-
Total Revenues		3,021			1,228			(915	)		3,334

Expenses:
Fuel		-			312			-			312
Purchased power		1,876			160			(893	)		1,143
Other operating expenses		499			355			(27	)		827
Provision for depreciation		109			64			4			177
Amortization of regulatory assets, net		411			-			-			411
Deferral of new regulatory assets		(93	)		-			-			(93	)
General taxes		170			32			9			211
Total Expenses		2,972			923			(907	)		2,988

Operating Income		49			305			(8	)		346
Other Income (Expense):
Investment income		30			(29	)		(12	)		(11	)
Interest expense		(110	)		(28	)		(56	)		(194	)
Capitalized interest		1			10			17			28
Total Other Expense		(79	)		(47	)		(51	)		(177	)

Income Before Income Taxes		(30	)		258			(59	)		169
Income taxes		(12	)		103			(37	)		54
Net Income (Loss)		(18	)		155			(22	)		115
Noncontrolling interest loss		-			-			(4	)		(4	)
Earnings available to FirstEnergy Corp.	$	(18	)	$	155		$	(18	)	$	119

Changes Between First Quarter 2010 and
First Quarter 2009 Financial Results
Increase (Decrease)

Revenues:
External
Electric	$	(463	)	$	389		$	-		$	(74	)
Other		(15	)		(8	)		(5	)		(28	)
Internal		-			(219	)		286			67
Total Revenues		(478	)		162			281			(35	)

Expenses:
Fuel		-			25			(3	)		22
Purchased power		(481	)		290			286			95
Other operating expenses		(119	)		(8	)		1			(126	)
Provision for depreciation		4			2			10			16
Amortization of regulatory assets		(199	)		-			-			(199	)
Deferral of new regulatory assets		93			-			-			93
General taxes		(8	)		3			(1	)		(6	)
Total Expenses		(710	)		312			293			(105	)

Operating Income		232			(150	)		(12	)		70
Other Income (Expense):
Investment income		(5	)		30			2			27
Interest expense		(14	)		(25	)		20			(19	)
Capitalized interest		-			10			3			13
Total Other Expense		(19	)		15			25			21

Income Before Income Taxes		213			(135	)		13			91
Income taxes		81			(56	)		32			57
Net Income (Loss)		132			(79	)		(19	)		34
Noncontrolling interest loss		-			-			(2	)		(2	)
Earnings available to FirstEnergy Corp.	$	132		$	(79	)	$	(17	)	$	36

Energy Delivery Services – First Quarter 2010 Compared with First Quarter 2009

Net income increased to $114 million in the first quarter of 2010, compared to a loss of $18 million in the first quarter of 2009, primarily due to the absence of CEI’s $216 million regulatory asset impairment in 2009, lower purchased power costs and lower other operating expenses, partially offset by lower revenues and the absence of deferrals of new regulatory assets.

~~Debt Capacity~~Revenues –

The decrease in total revenues resulted from the following sources:

	Three Months
	Ended March 31				Increase
Revenues by Type of Service	2010		2009		(Decrease)
	(In millions)
Distribution services	$	883	$	849	$	34
Generation sales:
Retail		1,176		1,613		(437	)
Wholesale		217		188		29
Total generation sales		1,393		1,801		(408	)
Transmission		215		318		(103	)
Other		52		53		(1	)
Total Revenues	$	2,543	$	3,021	$	(478	)

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

Electric Distribution KWH Deliveries
Residential	(3	)%
Commercial	(1	)%
Industrial	7	%
Total Distribution KWH Deliveries	-	%

Lower deliveries to residential customers reflected decreased weather-related usage in the first quarter of 2010, as heating degree days decreased by 7% from the same period in 2009. The increase in distribution deliveries to industrial customers was primarily due to a slightly recovering economy in FirstEnergy's service territory compared to the first quarter of 2009. In the industrial sector, KWH deliveries increased to major automotive customers (14%) and ~~Financing Activities~~ ~~(Applicable~~steel customers (31%). Distribution service revenues increased primarily due to ~~FES~~the accelerated recovery of deferred distribution costs, as approved by the PUCO, partially offset by a reduction in the transition rate for CEI effective June 1, 2009.

The following table summarizes the price and ~~each~~volume factors contributing to the $408 million decrease in generation revenues in the first quarter of 2010 compared to the first quarter of 2009:

Source of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 30.6% decrease in sales volumes	$	(494	)
Change in prices		57
		(437	)
Wholesale:
Effect of 14.3% decrease in sales volumes		(27	)
Change in prices		56
		29
Decrease in Generation Revenues	$	(408	)

The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in the Ohio Companies’ service territories in the first quarter of 2010. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries for the Ohio Companies increased 53% in the first quarter of 2010 compared to the same period in 2009. Retail generation prices increased primarily for CEI as a result of the ~~Utilities)~~CBP auction for the service period beginning June 1, 2009.

The increase in wholesale generation revenues reflected higher prices for Met-Ed’s and Penelec’s NUG sales to the PJM market.

Transmission revenues decreased $103 million primarily due to the termination of the Ohio Companies’ transmission tariff effective June 1, 2009; recovery of transmission costs is now provided for in the generation rate established under the CBP.

Expenses –

Total expenses decreased by $710 million due to the following:

Purchased power costs were $481 million lower in the first quarter of 2010 due to lower volume requirements, partially offset by an increase in unit costs from non-affiliates. The decrease in purchased power volumes resulted principally from the increase in customer shopping in the Ohio Companies’ service territories, as described above.

The increase in unit costs from non-affiliates in the first quarter of 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec compared to the first quarter of 2009. The decrease in unit costs from FES was principally due to the lower weighted average unit price per KWH for the Ohio Companies established under the CBP auction effective June 1, 2009.

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	187
Change due to decreased volumes		(419	)
		(232	)
Purchases from FES:
Change due to decreased unit costs		(94	)
Change due to decreased volumes		(152	)
		(246	)

Increase in NUG costs deferred		(3	)
Net Decrease in Purchased Power Costs	$	(481	)

·	MISO network transmission expenses were lower by $54 million due to the reduced generation sales requirements discussed above.

·	Administrative and general costs, including labor and employee benefit expenses, decreased $49 million as a result of cost reduction initiatives implemented since the first quarter of 2009.

·	Other operating expenses decreased $21 million due to higher economic development expenses recognized in the first quarter of 2009 relating to the amended ESP.

·	Forestry contractor costs were $4 million higher in the first quarter of 2010, reflecting increased vegetation management activities.

Amortization of regulatory assets decreased $199 million due primarily to the absence of the $216 million impairment of CEI’s regulatory assets in the first quarter of 2009 and reduced CTC amortization for Met-Ed and Penelec, partially offset by a $35 million regulatory asset impairment associated with the filing of the ESP on March 23, 2010.

·	The deferral of new regulatory assets decreased $93 million in the first quarter of 2010 principally due to the absence of CEI’s PUCO-approved purchased power cost deferral in the first quarter of 2009.

·	Depreciation expense increased $4 million due to property additions since the first quarter of 2009.

·	General taxes decreased $8 million primarily due to lower property and real estate taxes.

Other Expense –

Other expense increased $19 million in the first quarter of 2010 compared to the first quarter of 2009 primarily due to higher interest expense associated with debt issuances by the Utilities since the first quarter of 2009.

Competitive Energy Services – First Quarter 2010 Compared with First Quarter 2009

Net income decreased to $76 million in the first quarter of 2010, compared to $155 million in the first quarter of 2009, primarily due to a decrease in sales margins partially offset by an increase in investment income.

Revenues –

Total revenues increased $162 million in the first quarter of 2010 primarily due to an increase in direct and government aggregation sales volumes and sales of RECs, partially offset by decreases in PLR sales to the Ohio Companies and wholesale sales.

The increase in total revenues resulted from the following sources:

	Three Months
	Ended March 31				Increase
Revenues by Type of Service	2010		2009		(Decrease)
	(In millions)

Direct and Government Aggregation	$	512	$	91	$	421
PLR		677		893		(216	)
Wholesale		87		189		(102	)
Transmission		17		25		(8)
RECs		67		-		67
Other		30		30		-
Total Revenues	$	1,390	$	1,228	$	162

The increase in direct and government aggregation revenues of $421 million resulted from increased revenue in both the MISO and PJM markets. The increase in revenue is primarily the result of the acquisition of new customers and the inclusion of the transmission-related component in MISO retail rates, partially offset by lower unit prices. The acquisition of new customers is primarily due to new commercial and industrial customers as well as new government aggregation contracts with communities in Ohio that provide generation to approximately one million residential and small commercial customers. During January 2010, FES began supplying power to approximately 425,000 NOPEC customers.

The decrease in PLR revenues of $216 million were due to lower sales volumes to the Ohio Companies and lower unit prices, partially offset by increased sales volumes and higher unit prices to the Pennsylvania Companies. The lower sales volumes and unit prices to the Ohio Companies in the first quarter 2010 reflected the results of the May 2009 power procurement processes. The increased revenues to the Pennsylvania Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a third-party contract and at prices that were slightly higher than in the first quarter of 2009. The increase was partially offset by lower sales to Penn due to decreased default service requirements in 2010 compared to 2009.

Wholesale revenues decreased $102 million due to a 76.3% decline in volume reflecting market declines, partially offset by higher capacity prices.

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

Source of Change in Direct and Government Aggregation	Increase (Decrease)
	(In millions)
Direct Sales:
Effect of 471.5% increase in sales volumes	$	289
Change in prices		(30	)
		259
Government Aggregation:
Effect of an increase in sales volumes		162
Change in prices		-
		162
Net Increase in Direct and Gov’t Aggregation Revenues	$	421

Source of Change in Wholesale Revenues	Increase (Decrease)
	(In millions)
PLR:
Effect of 10.2% decrease in sales volumes	$	(91	)
Change in prices		(125	)
		(216	)
Wholesale:
Effect of 76.3% decrease in sales volumes		(112	)
Change in prices		10
		(102	)
Net Decrease in Wholesale Revenues	$	(318	)

Transmission revenues decreased $8 million due primarily to the inclusion of the transmission-related component in the retail rates beginning in mid-2009 as a result of the CBP.

In the first three months of 2010, FES sold $67 million of RECs.

Expenses -

Total expenses increased $312 million in the first quarter of 2010 due to the following:

Fuel costs increased $25 million due to increased unit prices ($36 million) partially offset by reduced generation volumes ($11 million). The increase in unit prices was due primarily to higher coal transportation charges ($10 million) and higher nuclear fuel unit prices following the refueling outages that occurred in 2009 ($16 million).

·	Purchased power costs increased $290 million due primarily to higher volumes purchased ($300 million) and power contract mark-to-market adjustments ($52 million), partially offset by lower unit costs ($62 million).

·	Nuclear operating costs decreased $21 million due primarily to lower labor, employee benefit expenses and professional and contractor costs. The first quarter of 2010 had fewer refueling outages than the first quarter of 2009, decreasing operating costs by approximately $5 million.

·	Transmission expense increased $7 million due primarily to increased costs in MISO of $43 million from higher network and ancillary costs, partially offset by lower PJM transmission expense of $36 million due to lower congestion and loss expenses.

·	Other expense increased $5 million primarily due to increases in uncollectible customer accounts and agent fees associated with the increase in retail sales.

·	Higher depreciation expense of $2 million was due primarily to increased property additions since the first quarter of 2009.

·	General taxes increased $3 million due to sales taxes.

Other Expense –

Total other expense in the first quarter of 2010 was $15 million lower than the first quarter of 2009, primarily due to a $30 million increase in investment income resulting from a reduction to impairments in the value of nuclear decommissioning trust investments, partially offset by a $15 million increase in interest expense. Interest expense increased primarily due to new issuances of long-term debt combined with the restructuring of existing long-term debt.

Other – First Quarter 2010 Compared with First Quarter 2009

FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $17 million decrease in earnings available to FirstEnergy Corp. in the first three months of 2010 compared to the same period in 2009. The decrease resulted primarily from the absence of a favorable tax resolution that occurred in the first quarter of 2009 ($13 million) and charges recorded in the first quarter of 2010 associated with the termination of gas drilling participation rights associated with certain previously owned Ohio properties ($5 million, after tax).

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 2010 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 March 31, 2010, FirstEnergy's net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($0.9 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debt as of March 31, 2010, included the following (in millions):

Currently Payable Long-term Debt
PCRBs supported by bank LOCs(1)	$	1,553
FGCO and NGC unsecured PCRBs(1)	65
Penelec FMBs(2)	24
NGC collateralized lease obligation bonds	44
Sinking fund requirements	34
Other notes(2)	63
	$	1,783

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

Short-Term Borrowings

FirstEnergy had approximately $0.9 billion of short-term borrowings as of March 31, 2010 and $1.2 billion as of December 31, 2009. FirstEnergy's available liquidity as of April 30, 2010, is summarized in the following table:

Company	Type	Maturity	Commitment		Available Liquidity as of April 30, 2010
			(In millions)
FirstEnergy(1)	Revolving	Aug. 2012	$	2,750	$	1,380
FirstEnergy Solutions	Bank line	Mar. 2011		100		-
Ohio and Pennsylvania Companies	Receivables financing	Various(2)		345		272
		Subtotal	$	3,195	$	1,652
		Cash		-		357
		Total	$	3,195	$	2,009

(1) FirstEnergy Corp. and subsidiary borrowers. (2) Ohio - $200 million (March – May 2010), $250 million (June 2010 – February 2011) matures March 30, 2011; Pennsylvania - $145 million matures December 17, 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. A total of 25 banks participate in the facility, with no one bank having more than 7.3% of the total commitment. 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.

	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			33	(2)
CEI		250	(3)		500
TE		250	(3)		500
JCP&L		425			411	(2)
Met-Ed		250			300	(2)
Penelec		250			300	(2)
ATSI		50	(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 ATSI has received regulatory

approval to have short-term borrowings up to the same amount.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of March 31, 2010, FirstEnergy's and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy(1)	61.2	%
FES	54.2	%
OE	54.3	%
Penn	31.9	%
CEI	59.8	%
TE	59.5	%
JCP&L	36.1	%
Met-Ed	39.5	%
Penelec	54.2	%
ATSI	51.1	%

(1)As of March 31, 2010, FirstEnergy could issue additional debt of approximately

$2.8 billion, or recognize a reduction in equity of approximately $1.5 billion, and

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

credit facility.

FirstEnergy Money Pools

FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first three months of 2010 was 0.4 9% for the regulated companies' money pool and 0.54% for the unregulated companies' money pool.

Pollution Control Revenue Bonds

As of March 31, 2010, 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 as of March 31, 2010:

	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	284		Beginning April 2011	Multiple dates(4)
The Royal Bank of Scotland	131		June 2012	6 months
KeyBank(1)	237		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 58% 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. (4) Shorter of 6 months or LOC termination date ($155 million) and shorter of one year or LOC termination date ($129 million).

In April 2010, FGCO purchased approximately $235 million variable rate PCRBs and cancelled its $237 million LOC with KeyBank as shown above. FGCO plans to remarket these securities into a fixed rate mode during 2010.

~~Long-Term Debt Capacity~~Pollution Control Revenue Bonds

As of ~~June 30, 2009,~~March 31, 2010, 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 ~~Ohio Companies and Penn had~~bondholders of which are entitled to the ~~aggregate capability to issue approximately $2.3 billion~~benefit of ~~additional FMBs~~irrevocable direct pay bank LOCs. The interest rates on the ~~basis of property additions and retired bonds under~~PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the ~~terms of their respective mortgage indentures.~~purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The ~~issuance of FMBs~~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 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,following banks 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.March 31, 2010:

	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	284		Beginning April 2011	Multiple dates(4)
The Royal Bank of Scotland	131		June 2012	6 months
KeyBank(1)	237		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 58% 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. (4) Shorter of 6 months or LOC termination date ($155 million) and shorter of one year or LOC termination date ($129 million).

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~~April 2010, FGCO purchased approximately $235 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 ofvariable rate PCRBs and ~~approximately $380~~cancelled its $237 million ~~related~~LOC with KeyBank as shown above. FGCO plans 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~~remarket these securities into 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.fixed rate mode during 2010.

~~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~~

Pollution Control Revenue Bonds

As of ~~June 30, 2009, FES’, Met-Ed’s and Penelec’s~~March 31, 2010, FirstEnergy's currently payable long-term debt included approximately $1.6 billion (FES - $1.5 billion, Met-Ed - $29 million and Penelec - $45 ~~million, respectively,~~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 as of March 31, 2010:

	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	284		Beginning April 2011	Multiple dates(4)
The Royal Bank of Scotland	131		June 2012	6 months
KeyBank(1)	237		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 58% 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. (4) Shorter of 6 months or LOC termination date ($155 million) and shorter of one year or LOC termination date ($129 million).

In ~~February 2009, holders~~April 2010, FGCO purchased approximately $235 million variable rate PCRBs and cancelled its $237 million LOC with KeyBank as shown above. FGCO plans to remarket these securities into a fixed rate mode during 2010.

Long-Term Debt Capacity

As of March 31, 2010, the Ohio Companies and Penn had the aggregate capability to issue approximately ~~$434 million principal~~$2.3 billion of ~~LOC-supported PCRBs~~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 ~~NGC were notified that the applicable Wachovia Bank LOCs were~~CEI to ~~expire on~~incur additional secured debt not otherwise permitted by a specified exception of up to $101 million and $17 mill ion, respectively, as of March ~~18, 2009.~~31, 2010. As a result ~~these PCRBs were subject~~of the indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to ~~mandatory purchase at~~issue secured debt of approximately $379 million and $345 million, respectively, under provisions of their senior note indentures as of March 31, 2010.

Based upon FGCO's FMB indenture, net earnings and available bondable property additions as of March 31, 2010, FGCO had the capability to issue $2.4 billion of additional FMBs under the terms of that indenture. In June 2009, a ~~price equal~~new FMB indenture became effective for NGC. Based upon NGC’s FMB indenture, net earnings and available bondable property additions, NGC had the capability to ~~the principal amount, plus accrued and unpaid interest, which OE and NGC funded through short-term borrowings. In March 2009, FGCO remarketed $100~~issue $294 million of ~~those PCRBs, which were previously held by OE. During the second quarter~~additional FMBs as 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.March 31, 2010.

~~Financing Activities~~

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

~~109~~74

~~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~~FirstEnergy's access to capital markets and costs of financing are influenced by the ~~outstanding common stock~~ratings of its ~~principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES~~securities. On February 11, 2010, S&P issued a report lowering FirstEnergy’s and its subsidiaries ~~FGCO~~credit ratings by one notch, while maintaining its stable outlook. Moody’s and ~~NGC,~~Fitch affirmed the ratings and ~~FESC.~~

stable outlook of 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 SectionFebruary 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.2010. The following table ~~reconciles basic~~displays FirstEnergy's, FES' and ~~diluted earnings per share~~the Utilities' securities ratings as 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~~March 31, 2010.

~~(A)~~ Issuer	~~LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS~~ Senior Secured			Senior Unsecured
~~(A)~~ Issuer	S&P	Moodys	Fitch	S&P	Moodys	Fitch
FirstEnergy Corp.	-	-	-	BB+	Baa3	BBB

FirstEnergy Solutions	-	-	-	BBB-	Baa2	BBB

Ohio Edison	BBB	A3	BBB+	BBB-	Baa2	BBB

Pennsylvania Power	BBB+	A3	BBB+	-	-	-

Cleveland Electric Illuminating	BBB	Baa1	BBB	BBB-	Baa3	BBB-

Toledo Edison	BBB	Baa1	BBB	-	-	-

Jersey Central Power & Light	-	-	-	BBB-	Baa2	BBB+

Metropolitan Edison	BBB	A3	BBB+	BBB-	Baa2	BBB

Pennsylvania Electric	BBB	A3	BBB+	BBB-	Baa2	BBB

ATSI	-	-	-	BBB-	Baa1	-

~~All borrowings with initial maturities~~

Changes in Cash Position

As of ~~less than one year are defined~~March 31, 2010, FirstEnergy had $310 million in cash and cash equivalents compared to $874 million as ~~short-term financial instruments under GAAP~~of December 31, 2009. As of March 31, 2010 and ~~are reported~~December 31, 2009, FirstEnergy had approximately $12 million of restricted cash included in other current assets 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:Sheet.

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~~During 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~~first three months ~~or less are reported as~~of 2010, FirstEnergy received $620 million of cash ~~equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than~~dividends from its subsidiaries and paid $168 million in 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~~dividends 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.common shareholders.

~~Available-For-Sale Securities~~Cash Flows From Operating Activities

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

~~(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~~net cash from operating activities is provided primarily by its competitive energy services 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~~energy delivery services businesses (see Results of Operations above). Net cash provided from operating activities increased by $44 million during the ~~consolidated financial statements~~first three months 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~~

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 as2010 compared 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~~comparable period in 2009, 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.

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.

~~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 shownsummarized 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~~

	Three Months Ended March 31
Operating Cash Flows	2010			2009			Increase (Decrease)
	(In millions)
Net income	$	149		$	115		$	34
Non-cash charges and other adjustments		367			375			(8	)
Working capital and other		(10	)		(28	)		18
	$	506		$	462		$	44

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.

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 bondsdecrease in non-cash charges and other ~~fees and expenses associated with their issuance. JCP&L sold its bondable transition property~~adjustments is primarily due to ~~JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property,~~lower net amortization of regulatory assets ($106 million), 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.

~~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 yearCEI’s $216 million regulatory asset impairment recorded in the first quarter of 2009, ~~FirstEnergy recognized $13 million in~~partially offset by higher net deferred income taxes and investment tax ~~benefits, which favorably affected FirstEnergy's effective tax rate. During the second quarter of 2009~~credits ($87 million) 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 penaltiesan increase in the provision for ~~income taxes.~~depreciation ($16 million). The ~~net amount of accumulated~~changes in working capital and other primarily resulted from a $104 million decrease in prepayments and other current assets and an $58 million increase in accrued taxes, partially offset by a $52 million decrease in accrued interest, a $44 million increase in receivables and a $31 million increase in cash collateral paid. The change in 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~~taxes and ~~2008, there were no material changes~~prepayments primarily relates to the ~~amount~~timing of income ta x payments. The decrease in accrued interest ~~accrued.~~

~~In 2008, FirstEnergy, on behalf of FGCO and NGC, filed a change in accounting method related~~primarily relates to the ~~costs to repair and maintain electric generation stations. During the second quarter~~$1.2 billion tender offer 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 accruedholding company notes in the third quarter of 2009 combined with ~~no corresponding impact~~the timing of payments relating to ~~the effective tax rate for the quarter.~~new debt issuances in 2009.

~~121~~75

Cash Flows From Financing Activities

~~FirstEnergy has tax returns that are under review at~~In the ~~audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open~~first three months of 2010, cash used for financing activities was $594 million compared to cash provided 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 completedfinancing activities of $70 million in the first ~~quarter~~three months of ~~2009 with two items under appeal.~~2009. The ~~IRS began auditing the year 2008~~decrease was primarily due to new debt issuances in ~~February 2008~~2009 and the ~~year 2009~~repayment of short-term borrowings 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~~2010, partially offset by decreased long-term debt redemptions in 2010. The following table summarizes security issuances (net of any discounts) and ~~final settlement of these audits is not expected to have a material adverse effect on FirstEnergy's financial condition or results of operations.~~redemptions.

	Three Months Ended
	March 31
Securities Issued or Redeemed	2010			2009
	(In millions)
New issues
Pollution control notes	$	-		$	100
Unsecured notes		-			600
	$	-		$	700

Redemptions
Pollution control notes	$	-		$	437
Senior secured notes		9			7
Met-Ed unsecured notes		100			-
	$	109		$	444

Short-term borrowings, net	$	(295	)	$	-

~~8. COMMITMENTS, GUARANTEES AND CONTINGENCIES~~

Cash Flows From Investing Activities

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 distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for the three months ended March 31, 2010 and 2009 by business segment:

Summary of Cash Flows	Property
Provided from (Used for) Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Three Months Ended March 31, 2010
Energy delivery services	$	(166	)	$	62		$	(7	)	$	(111	)
Competitive energy services		(323	)		-			(1	)		(324	)
Other		(3	)		-			-			(3	)
Inter-Segment reconciling items		(16	)		(22	)		-			(38	)
Total	$	(508	)	$	40		$	(8	)	$	(476	)

Three Months Ended March 31, 2009
Energy delivery services	$	(165	)	$	51		$	(14	)	$	(128	)
Competitive energy services		(421	)		2			(19	)		(438	)
Other		(49	)		(20	)		1			(68	)
Inter-Segment reconciling items		(19	)		(25	)		-			(44	)
Total	$	(654	)	$	8		$	(32	)	$	(678	)

Net cash used for investing activities in the first three months of 2010 decreased by $202 million compared to the first three months of 2009. The decrease was principally due to a $146 million decrease in property additions, which reflects lower AQC system expenditures, and cash proceeds of approximately $114 million from the sale of assets, partially offset by $101 million relating to the acquisition of customer intangible assets.

~~(A)~~ During the remaining three quarters of 2010, capital requirements for property additions and capital leases are expected to be approximately $1.1 billion. These cash requirements are expected to be satisfied from a combination of internal cash and short-term credit arrangements.

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 either FirstEnergy or its subsidiaries’ credit ratings.

As of ~~June 30, 2009,~~March 31, 2010, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances ~~aggregated~~approximated $4.0 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)	$	324
LOC (long-term debt) – interest coverage (2)		6
FirstEnergy guarantee of OVEC obligations		300
Other (3)		297
		927

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		2,464
		2,601

Surety Bonds		77
LOC (long-term debt) – interest coverage (2)		3
LOC (non-debt) (4)(5)		423
		503
Total Guarantees and Other Assurances	$	4,031

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

assurances and $161 million supporting OE’s sale and leaseback arrangement.

(4) Includes $231 million issued for various terms pursuant to LOC capacity available

under FirstEnergy’s revolving credit facility.

(5) Includes approximately ~~$4.6 billion, consisting primarily~~$145 million pledged in connection with the sale and

leaseback of ~~parental guarantees - $1.3 billion, subsidiaries’ guarantees - $2.6 billion, surety bonds - $0.1 billion~~Beaver Valley Unit 2 by OE and ~~LOCs - $0.5 billion.~~$47 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 ~~financing~~financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, ~~FirstEnergy's~~FirstEnergy’s guarantee enables the counterparty's legal claim to be ~~satisfied~~satisf ied by ~~other~~FirstEnergy’s assets. FirstEnergy ~~assets. The~~believes 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~~will increase amounts otherwise ~~payable~~paid by FirstEnergy to meet its obligations incurred in connection with ~~financings and~~ ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade to below investment grade, an acceleration or funding obligation, or a “material adverse event,” the immediate posting of cash collateral, provision of ana LOC or accelerated payments may be required of the subsidiary. On February 11, 2010, S&P issued a report lowering FirstEnergy’s and its subsidiaries’ credit ratings by one notch, while maintaining its stable outlook. As a result, FirstEnergy was required to post $46 million of collateral. Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries. As of ~~June 30, 2009, FirstEnergy's~~March 31, 2010, FirstEnergy’s maximum exposure under these collateral provisions was ~~$601~~$428 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~~as shown below:

Collateral Provisions	FES		Utilities		Total
	(In millions)
Credit rating downgrade to below investment grade	$	318	$	10	$	328
Acceleration of payment or funding obligation		15		48		63
Material adverse event		37		-		37
Total	$	370	$	58	$	428

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~~the total potential amount to ~~$700~~$656 million, consisting of ~~$49~~$38 million due to “material adverse event” contractual clauses, $63 million due to an acceleration of payment or funding obligation, and ~~$651~~$555 million due to a below investment grade credit rating.

Most of ~~FirstEnergy's~~FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of ~~$108~~$77 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~~power portfolio as of ~~June 30, 2009,~~March 31, 2010, and forward prices as of that date, FES ~~had $179 million~~has posted collateral of ~~outstanding collateral payments.~~$270 million. Under a hypothetical adverse change in forward prices ~~(15% decrease~~(95% confidence level change in ~~the first 12 months and 20% decrease in~~forward prices ~~thereafter)~~over a one year time horizon), FES would be required to post an additional ~~$73~~$168 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~~

OFF-BALANCE SHEET ARRANGEMENTS

MARKET RISK INFORMATION

Commodity Price Risk

FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices associated with electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Certain derivatives must be recorded at their fair value and marked to market. The majority of FirstEnergy's derivative hedging contracts qualify for the normal purchase and normal sale exception and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structure d pursuant to the Public Utility Regulatory Policies Act of 1978 and certain purchase power contracts (Note 4). The NUG entities non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs or regulatory liability for below-market costs. The following table sets forth the change in the fair value of commodity derivative contracts related to energy production as of March 31, 2010:

Increase (Decrease) in the Fair Value of Derivative Contracts	Non-Hedge			Hedge			Total
	(In millions)
Change in the Fair Value of Commodity Derivative Contracts:
Outstanding net liability as of January 1, 2010	$	(630	)	$	(15	)	$	(645	)
Additions/change in value of existing contracts		(276	)		(6	)		(282	)
Settled contracts		94			7			101
Outstanding net liability as of March 31, 2010(1)	$	(812	)	$	(14	)	$	(826	)

Non-Commodity Net Liabilities as of March 31, 2010:
Interest rate swaps	$	-		$	(2	)	$	(2	)

Net Liabilities-Derivative Contracts as of March 31, 2010	$	(812	)	$	(16	)	$	(828	)

Impact of Changes in Commodity Derivative Contracts(2)
Income Statement effects (pre-tax)	$	(27	)	$	-		$	(27	)
Balance Sheet effects:
OCI (pre-tax)	$	-		$	1		$	1
Regulatory asset (net)	$	155		$	-		$	155

(1) Includes $580 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are subject to regulatory accounting and do not impact earnings. (2) Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

Derivatives are included on the Consolidated Balance Sheet as of March 31, 2010 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	1		$	39		$	40
Other liabilities		(140	)		(47	)		(187	)

Non-Current-
Other deferred charges		158			22			180
Other non-current liabilities		(831	)		(30	)		(861	)
Net liabilities	$	(812	)	$	(16	)	$	(828	)

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 3 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of March 31, 2010 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2010			2011			2012			2013			2014			Thereafter		Total
	(In millions)
Prices actively quoted(1)	$	(8	)	$	-		$	-		$	-		$	-		$	-	$	(8	)
Other external sources(2)		(409	)		(374	)		(166	)		(59	)		-			-		(1,008	)
Prices based on models		-			-			-			-			(1	)		192		191
Total(3)	$	(417	)	$	(374	)	$	(166	)	$	(59	)	$	(1	)	$	192	$	(825	)

(1) Represents exchange traded NYMEX futures and options.

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

(3) Includes $580 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts.

NUG contracts are subject to regulatory accounting and do not impact earnings.

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of March 31, 2010. Based on derivative contracts held as of March 31, 2010, an adverse 10% change in commodity prices would decrease net income by approximately $4 million during the next 12 months.

Interest Rate Swap Agreements – Fair Value Hedges

FirstEnergy uses fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. As of March 31, 2010, the debt underlying the $950 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.5%, which the swaps have converted to a current weighted average variable rate of 3.74%. The fair value of the interest rate swaps designated as fair value hedges was immaterial as o f March 31, 2010.

On April 29, 2010, April 30, 2010 and May 3, 2010, FirstEnergy executed multiple fixed-for-floating interest rate swap agreements with combined notional amounts of $1.3 billion, $300 million and $600 million, respectively, to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. This is consistent with FirstEnergy’s risk management policy and its 2010 financial plan. These derivatives will be treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of May 3, 2010, the debt underlying the $2.2 billion outstanding notional amount of interest rate swaps had a weighted average fixed intere st rate of 6%, which the swaps have converted to a current weighted average variable rate of 3.4%.

Forward Starting Swap Agreements - Cash Flow Hedges

FirstEnergy used 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 were 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 three months of 2010, FirstEnergy terminated forward swaps with a notional value of $100 million. The termination of the forward starting swap agreements did not materially impact FirstEnergy’s net income and no forward starting swap agreements were outstanding as of March 31, 2010.

Equity Price Risk

Nuclear decommissioning trust funds have been established to satisfy NGC's and the Utilities' nuclear decommissioning obligations. As of March 31, 2010, approximately 17% of the funds were invested in equity securities and 83% 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 $311 million as of March 31, 2010. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $31 million reduction in fair value as of March 31, 2010. 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 as other-than-temporary impairments. FirstEnergy continues to evaluate the status of its funding obligations for the decommissioning of these nuclear facilities and does not expect to make additional cash contributions to the nuclear decommissioning trusts in 2010 other than the required annual trust contributions.

CREDIT RISK

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of March 31, 2010, the largest credit concentration was with J. Aron & Company, which is currently rated investment grade, representing 7.4% of FirstEnergy’s total approved credit risk.

OUTLOOK

As a result of economic conditions and the milder weather experienced in the first quarter of 2010, 2010 distribution sales are expected to be approximately 106 million MWH in 2010, while generation output for 2010 is expected to be 77.1 million MWH.

State Regulatory Matters

Regulatory assets that do not earn a current return totaled approximately $213 million as of March 31, 2010 (JCP&L - $46 million, Met-Ed - $122 million, and Penelec - $47 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 regulatory assets by company:

	March 31,		December 31,		Increase
Regulatory Assets	2010		2009		(Decrease)
	(In millions)
OE	$	432	$	465	$	(33	)
CEI		498		546		(48	)
TE		82		70		12
JCP&L		856		888		(32	)
Met-Ed		393		357		36
Penelec		119		9		110
Other		18		21		(3	)
Total	$	2,398	$	2,356	$	42

Regulatory assets by source are as follows:

	March 31,			December 31,			Increase
Regulatory Assets By Source	2010			2009			(Decrease)
	(In millions)
Regulatory transition costs	$	1,219		$	1,100		$	119
Customer shopping incentives		113			154			(41	)
Customer receivables for future income taxes		335			329			6
Loss on reacquired debt		50			51			(1	)
Employee postretirement benefits		21			23			(2	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(174	)		(162	)		(12	)
Asset removal costs		(235	)		(231	)		(4	)
MISO/PJM transmission costs		157			148			9
Fuel costs		377			369			8
Distribution costs		431			482			(51	)
Other		104			93			11
Total	$	2,398		$	2,356		$	42

Reliability Initiatives

In 2005, Congress amended the FPA 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 FPA 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 that could have a material adverse effect on its financial condition, results of operations and cash flows.

In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the Midwest ISO region and found it to be in full compliance with all audited reliability standards. Similarly, 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. FirstEnergy’s MISO facilities are next due for the periodic audit by ReliabilityFirst later this year.

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 required 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 replied as requested on August 6, 2009. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittals or interview results.

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 (out of approximately 20,000 reportable 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. The NERC approved FirstEnergy’s mitigation plan on August 19, 200 9, and submitted it to the FERC for approval on August 19, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-reported violation.

Ohio

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing. On January 21, 2009, the PUCO granted the Ohio Companies’ application in part 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.

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 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 w rite-off approximately $216 million of its Extended RTC regulatory asset, 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 con tained 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.

SB221 also requires electric distribution utilities to implement energy efficiency programs. Under the provisions of SB221, the Ohio Companies are required to 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, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional .75% reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies have filed an application with the PUCO seeking such amendments. On January 7, 2010, the PUCO amended the 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years. On March 10, 2010, the PUCO found that due to a change in PUCO rules subsequent to the filing of the Ohio Companies’ application, the Ohio Companies’ application seeking a reduction of the peak demand reduction requirements was moot. In its March 10, 2010, Entry the PUCO also found that the Companies peak demand reduction programs complied with PUCO rules.

The Ohio Companies are presently involved in collaborative efforts related to energy efficiency programs, including filing applications for approval of those programs with the PUCO, as well as other implementation efforts arising out of the Supplemental Stipulation. On December 15, 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The PUCO set the matter for a hearing that was completed on March 8, 2010, and all briefing was completed by April 12, 2010. On March 8, 2010, the Ohio Companies filed their 2009 Status Update Report with the PUCO in which they indicated compliance with the 2009 statutory energy efficiency and peak demand benchmarks as those benchmarks were amended as described above. Interested parties filed comments on the Report. The PUCO has yet to address these comments. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers.

Additionally under SB221, 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. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs will be used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On December 7, 2009, the Ohio Companies filed an application with the PUCO seeking a force majeure determination regarding the Ohio Companies’ compliance with the 2009 solar energy resources benchmark, and seeking a reduction in the benchmark. On March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and thus granted the Ohio Companies’ application seeking force majeure. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies’ acquired through their 2009 RFP processes, provided the Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2010, the Ohio Companies and FES (due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy requirements in SB221 for 2009. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark, which application is still pending.

On October 20, 2009, the Ohio Companies filed an MRO to procure electric generation service for the period beginning June 1, 2011. The proposed MRO would establish a CBP to secure generation supply for customers who do not shop with an alternative supplier and would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility and supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009. Hearings took place in December 2009 and the matter has been fully briefed. Pursuant to SB221, the PUCO ha s 90 days from the date of the application to determine whether the MRO meets certain statutory requirements. Although the Ohio Companies requested a PUCO determination by January 18, 2010, on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements are met, the Ohio Companies would be able to implement the MRO and conduct the CBP.

On March 23, 2010, the Ohio Companies filed an application for a new ESP, which if approved by the PUCO, would go into effect on June 1, 2011 and conclude on May 31, 2014. Attached to the application was a Stipulation and Recommendation signed by the Ohio Companies, the Staff of the PUCO, and an additional fourteen parties signing as Signatory Parties, with two additional parties agreeing not to oppose the adoption of the Stipulation. The material terms of the Stipulation include a CBP similar to the one used in May 2009 and the one proposed in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided by the Ohio Companies through a bilateral wholesale contract with FES; no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider D CR), to recover a return of, and on, capital investments in the delivery system. This Rider replaces the Delivery Service Improvement Rider (Rider DSI) which terminates by its own terms. The Ohio Companies also agree not to collect certain amounts associated with RTEP and administrative costs associated with the move to PJM. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP also requests the resolution of current proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the move to PJM. The evidentiary hearing began on April 20, 2010, at the PUCO. The Stipulation requested a decision by the PUCO by May 5, 2010. On April 28, 2010, the PUCO Chairman issued a statement that the PUCO will not issue a decision on May 5, 2010, and will take additional time to review the case record. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP.

Pennsylvania

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 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 proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. On August 12, 2009, Met-Ed and Penelec filed a settlement agreement with the PPUC for the generation procurement plan covering the period January 1, 2011, through May 31, 2013, reflecting the settlement on all but two issues. The settlement plan proposes a staggered procurement schedule, which varies by customer class. On September 2, 2009, the ALJ issued a Recommended Decision (RD) approving the settlement and adopted the Met-Ed and Penelec’s positions on two reserved issues. On November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two reserved issues. Generation procurement began in January 2010.

On May 22, 2008, the PPUC approved Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The TSCs included a component for 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. 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. On August 11, 2009, the ALJ issued a Recommended Decision to the PPUC approving Met-Ed’s and Penelec’s TSCs as filed and dismissing all complaints. Exceptions by various interveners were filed and reply exceptions were filed by Met-Ed and Penelec. The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which denies the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directs Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructs Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. On March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of marginal transmission loss costs. By Order entered March 25, 2010, the PPUC granted the requested stay until December 31, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of Met-Ed and Penelec that they should prevail in the appeal and therefore expect to fully recover the approximately $199.7 million ($158.5 million for Met-Ed and $41.2 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On April 2, 2010, Met-Ed and Penelec filed a Response to the PPUC’s March 3, 2010 Order requesting approval of procedures to establish separate accounts to track all marginal transmission loss revenues and related interest and the use of those funds to mitigate future generation rate increases commencing January 1, 2011

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 subject to the outcome of the proceeding related to the 2008 TSC filing described above, 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 PPU C’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 would increase approximately 9.4% for the period June 2009 through May 2010.

Act 129 became effective in 2008 and addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. On July 1, 2009, Met-Ed, Penelec, and Penn filed EE&C Plans with the PPUC in accordance with Act 129. The Pennsylvania Companies submitted a supplemental filing on July 31, 2009, to revise the Total Resource Cost test items in the EE&C Plans pursuant to the PPUC’s June 23, 2009 O rder. Following evidentiary hearings and further revisions to the EE&C Plans, the Pennsylvania Companies filed final plans and tariff revisions on February 5, 2010 consistent with the minor revisions required by the PPUC. The PPUC entered an Order on February 26, 2010 approving the final plans and the tariff rider with rates effective March 1, 2010.

Legislation addressing rate mitigation and the expiration of rate caps was introduced in the legislative session that ended in 2008; several bills addressing these issues were introduced in the 2009 legislative session. The final form and impact of such legislation is uncertain.

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 - $59 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 fi led tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the Pennsylvania Companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings.

By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30-day comment period on whether “the Restructuring Settlement allows NUG over-collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.” In response to the Tentative Order, the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec filed reply comments on October 26, 2009. On November 5, 2009, the PPUC issued a Secretarial Letter allowing parties to file reply comments to Met-Ed and Penelec’s reply co mments by November 16, 2009, and reply comments were filed by the Office of Consumer Advocate, ARIPPA, and the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance. Met-Ed and Penelec are awaiting further action by the PPUC.

On February 8, 2010, Penn filed with the PPUC a generation procurement plan covering the period June 1, 2011 through May 31, 2013. The 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 proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. A preliminary conference was held on March 26, 2010, and, among other things, established a procedural schedule. Evidentiary hearings are scheduled for June 15-16, 2010. The PPUC is required to issue an order on the plan no later than November 8, 2010.

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 March 31, 2010, the accumulated deferred cost balance totaled approximately $55 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 al so 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.

~~(B)~~

~~ENVIRONMENTAL MATTERS~~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 New Jersey electric and gas utilities in order to achieve the goals of the EMP. On April 16, 2010, the BPU issued an order indefinitely suspending the requirement of the New Jersey utilities to submit Utility Master Plans until such time as the status of the EMP has been made clear. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations.

In support of former New Jersey Governor Corzine'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. In addition, 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. The project relating to expansion of the existing demand response programs was approved by the NJBPU on August 19, 2009, and implementation began in 2009. Approval for the project related to energy efficiency programs intended to complement those currently being offered was denied by the NJBPU on December 1, 2009. Implementation of the remaining 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 subj ect to review and approval by the FERC. 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. On October 29, 2009, March 17, 2010 and April 8, 2010, FirstEnergy, filed additional settlement agreements with FERC to resolve outstanding claims with various parties. FirstEnergy is actively pursuing settlement agreements with other parties to the case. On December 8, 2009, certain parties sought a writ of mandam us from the DC Circuit Court of Appeals directing FERC to issue an order on the Initial Decision. The Court agreed to hold this matter in abeyance based upon FERC’s representation to use good faith efforts to issue a substantive ruling on the initial decision no later than May 27, 2010. If FERC fails to act, the case will be submitted for briefing in June. The outcome of this matter cannot be predicted.

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 on the content of the compliance filings 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 zone s, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order (Opinion 494) 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 rea sonable cost allocation methodology for inclusion in PJM’s tariff.

The FERC’s April 19, 2007 order and related order denying a request for rehearing were appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision on August 6, 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a postage-stamp basis and, based on this finding, remanded the rate design issue back to FERC. A request for rehearing and rehearing en banc by two companies was denied by the Seventh Circuit on October 20, 2009.

The FERC’s orders on PJM rate design prevented 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 postage-stamp basis reduces the cost of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. FERC has no specific time frame to rule in this matter.

RTO Consolidation

On August 17, 2009, FirstEnergy filed an application with the FERC requesting to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The consolidation would make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s transmission assets in Pennsylvania and all of the transmission assets in New Jersey already operate as a part of PJM. Key elements of the filing include a Fixed Resource Requirement Plan (FRR Plan) that describes the means whereby capacity will be procured and administered as necessary to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years; and also a request that ATSI’s transmission customers be excused f rom the costs for regional transmission projects that were approved through PJM’s RTEP process prior to ATSI’s entry into PJM (legacy RTEP costs). The integration is expected to be complete on June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for the Ohio Companies. To ensure a definitive ruling at the same time the FERC rules on its request to integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a related complaint with the FERC on the issue of exempting the ATSI footprint from the legacy RTEP costs.

On September 4, 2009, the PUCO opened a case to take comments from Ohio’s stakeholders regarding the RTO consolidation. FirstEnergy filed extensive comments in the PUCO case on September 25, 2009, and reply comments on October 13, 2009, and attended a public meeting on September 15, 2009 to answer questions regarding the RTO consolidation. Several parties have intervened in the regulatory dockets at the FERC and at the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including an exit fee to MISO, integration costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO.

On March 10, 2010, FERC granted FirstEnergy’s request for expedited hearing on the conduct of the FRR auctions. The Ohio Companies and Penn obtained their PJM capacity requirements for the 2011 and 2012 delivery years in the FRR auctions conducted March 15-19, 2010. The PJM market monitor certified the FRR auction results on March 25, 2010, and the auction results were released by PJM on March 26, 2010. On March 29, 2010, the Ohio Companies and Penn signed agreements with all winning suppliers. In May 2010, the Ohio Companies and Penn’s load will be included in the PJM Base Residual Auction for the delivery year beginning 2013. FirstEnergy and unaffiliated generation and loads in the ATSI footprint are also expected to participate in the Base Residual Auction. FirstEnergy expects to integrate into PJM effective June 1, 2011.

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 FPA. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. 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, F irstEnergy 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. It ordered changes included making incremental improvements to RPM and 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; 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, 2009 Order.

MISO Complaints Versus PJM

On March 9, 2010, MISO filed two complaints against PJM with FERC under Sections 206, 306, and 309 of the FPA alleging violations of the MISO/PJM Joint Operating Agreement (JOA). In the first complaint, MISO alleged that by failing to account for the market flows from 34 PJM generators over the period from 2007-2009, PJM underpaid MISO by a total of roughly $75 million including interest. For the period from 2005-2007, MISO claimed an underpayment by PJM of at least $12 million plus interest. MISO also claimed that PJM failed to maintain required records necessary to calculate underbilling for the 2005-2007 billing.

PJM filed its answers to the complaints on April 12, 2010, opposing the relief sought by MISO. In addition, on April 12, 2010, PJM filed a complaint with FERC pursuant to Section 206, 306, and 309 alleging that MISO is violating the JOA with PJM by initiating market-to-market coordination and financial settlements for substitute (proxy) reciprocal coordinated flowgates between MISO and PJM. PJM claims that the JOA does not permit MISO to initiate market-to-market settlements using proxy flowgates in lieu of designated reciprocal coordinated flowgates. This complaint addresses substantially the same issues as the second MISO complaint, in which MISO argues that the use of proxy flowgates is permitted by agreement of the RTOs and operating practice. Each party filed a complaint in order to ensure their right to claim refunds, if any, if successful in their arguments at FERC.

FirstEnergy has intervened in all three proceedings, and timely filed comments supporting MISO in its first complaint, relating to improper accounting of market flows resulting in underpayments from 2005-2009. FirstEnergy is unable to predict the outcome of this matter.

Environmental Matters

Clean Air Act Compliance

~~123~~

In June ~~1, 2009, the Court held oral argument on Met-Ed’s motion to dismiss the complaint.~~

~~On May 16, 2008, FGCO received a request from~~

In August 2009, the EPA ~~for information pursuant to Section 114(a)~~issued a Finding of Violation and NOV alleging violations of the CAA ~~for certain operating~~ and ~~maintenance information regarding~~Ohio regulations, including the ~~Eastlake, Lakeshore, Bay Shore~~PSD, NNSR, 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 regardingTitle V regulations at the Eastlake, Lakeshore, Bay Shore, and Ashtabula generating plants. The EPA’s NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. In September 2009, FGCO received an information request pursuant to Section 114(a) of the CAA requesting certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shore and Ashtabula generating plants. On November 3, 2009, FGCO received a letter providing notification that the EPA is evaluating whether certain scheduled maintenance at the Eastlake generati ng plant may constitute a major modification under the NSR provision of the CAA. On December 23, 2009, FGCO received another information request regarding emission projections for the Eastlake generating plant pursuant to Section 114(a) of the CAA. FGCO intends to ~~fully~~ comply with the CAA, including EPA’s information requests, but, at this time, is unable to predict the outcome of this matter. A June 2006 finding of violation and NOV in which EPA alleged CAA violations at the Bay Shore Generating Plant remains unresolved and FGCO is unable to predict the outcome of such matter.

~~124~~

National Ambient Air Quality Standards

~~Mercury~~

Hazardous Air Pollutant 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~~U.S . 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 onin May ~~20,~~ 2008. OnIn October ~~17,~~ 2008, the EPA (and an industry group) petitioned the ~~United States~~U.S. 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~~On April 15, 2010, the EPA ~~is developing new~~entered into a consent decree requiring it to propose maximum achievable control technology (MACT) regulations for mercury ~~emission~~and other hazardous air pollutants by March 16, 2011, and to finalize the regulations by November 16, 2011. On April 29, 2010, the EPA issued proposed MACT regulations requiring emissions reductions of mercury and other hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels such as the proposed Burger biomass repowering project. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards ~~for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend~~applicable to electric generating units. Depending on the action taken by the EPA and on how any future regulations are ultimately ~~implemented.~~implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’s operations may result.

Climate Change

~~125~~

On April 2, 2007, the ~~United States~~U.S. 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,~~In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. Also in September 2009, the EPA proposed new thresholds for GHG emissions that define when CAA permits under the NS R and Title V operating permits programs would be required. The EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. The EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit. In December 2009, the EPA released ~~a “Proposed Endangerment~~its final “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 toGHG increase the threat of climate change. ~~Although~~In April 2010, EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles requiring an estimated combined average emissions level of 250 grams of CO2 per mile in model year 2016 and clarified that GHG regulation under the ~~EPA’s proposed finding, if finalized, does~~CAA will not ~~establish emission requirements~~be triggered 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~~and other stationary sources until January 2, 2011, at the earliest.

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~~U.S. 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~~authoritie s 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 U.S. 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. The EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. 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~~profess ional judgment, the future costs of compliance with these standards may require material capital expenditures.

Regulation of Waste Disposal

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion ~~waste products,~~residuals, 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,~~residuals, 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.~~residuals. In December 2009, the EPA provided to FGCO the findings of its review of t he Bruce Mansfield Plant’s coal combustion residuals management practices. The EPA observed that the waste management structures and the Plant “appeared to be well maintained and in good working order” and recommended only that FGCO “seal and maintain all asphalt surfaces.” On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA issued a proposed rule that provides two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FGCO's future cost of compliance with any coal combustion ~~waste~~residuals 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 EPA or the states.

~~126~~

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,~~March 31, 2010, 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~~$101 million (JCP&L&a mp;L - ~~- $77~~$74 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy ~~Corp.~~ - ~~$25~~$24 million) have been accrued through ~~June 30, 2009.~~March 31, 2010. Included in the total are accrued liabilities of approximately ~~$68~~$67 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.

~~(C) OTHER LEGAL PROCEEDINGS~~

Other Legal Proceedings

Power Outages and Related Litigation

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~~mo del 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~~Plaintiffs filed their appellate brief ~~is due~~ on August 25, 2009, and JCP~~&L's~~&L filed an opposition brief ~~is due~~ on September 25, 2009. On or about October 13, 2009, Plaintiffs filed their reply brief in further support of their appeal of the trial court's decision decertifying the class. The Appellate Division heard oral argument on January 5, 2010, before a three-judge panel. JCP&L is awaiting the Court’s decision.

Litigation Relating to the Proposed Allegheny Energy Merger

Nuclear Plant Matters

~~Nuclear Plant Matters~~Davis Besse Control Rod Drive Mechanism Nozzles

~~In August 2007,~~During a planned refueling outage at Davis Besse that began on February 28, 2010, FENOC ~~submitted an application to~~initially identified 16 of the 69 control rod drive mechanism (CRDM) nozzles that required modification. The Nuclear Regulatory Commission was notified of these findings, along with federal, state and local officials. The initial nozzle inspection process included ultrasonic (UT) testing and visual inspections. On March 18, 2010, the NRC sent a special inspection team 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.Davis-Besse.

~~127~~94

FENOC has begun a comprehensive investigation to determine the underlying cause for the cracking, and retained a contractor to make the necessary modifications. Modifications will be made using a proven industry method subject to NRC review. Further evaluation and testing identified 8 additional nozzles requiring modification. Additional testing will be conducted following the modification of each nozzle to ensure safe, reliable plant operations. The plant is expected to be ready for restart in July, 2010.

On April 5, 2010, the Union of Concerned Scientists (UCS) requested that the NRC issue a Show Cause Order, or otherwise delay the restart of the Davis Besse Nuclear Power Station until such time that the NRC determines that adequate protection standards have been met and reasonable assurance exists that these standards will continue to be met after the plant’s operation is resumed. What actions, if any, the NRC takes in response to this request have yet to be determined.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of ~~June 30, 2009,~~obligations. As of March 31, 2010, FirstEnergy had approximately ~~$1.7~~$1.9 billion invested in external trusts to be used for the decommissioning and environmental remediation of ~~Davis-Besse,~~Davis Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of ~~Davis-Besse,~~Davis Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy provided an additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010. ~~As required by~~By a letter dated March 8, 2010, primarily as a result of the Beaver V alley Power Station operating license renewal, FENOC requested that the NRC reduce FirstEnergy ~~annually recalculates and adjusts the amount of its~~ parental guarantee ~~as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based~~to $15 million and notified the staff that it no longer planned to make the additional contributions into the trusts. FirstEnergy is awaiting the NRC’s decision on ~~market conditions. If~~ the ~~value~~proposed reduction 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 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 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.guarantee.

Other Legal Matters

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

In 2010, the FASB amended the Derivatives and Hedging Topic of the FASB Accounting Standards Codification to clarify the scope exception for embedded credit derivative features related to the transfer of credit risk in the form of subordination of one financial instrument to another. The amendment addresses how to determine which embedded credit derivative features, including those in collateralized debt obligations and synthetic collateralized debt obligations, are considered to be embedded derivatives that should not be analyzed under the Derivatives and Hedging Topic for potential bifurcation and separate accounting. The amendment is effective for the first fiscal quarter beginning after June 15, 2010. FirstEnergy does not expect this standard to have a material effect on its financial statements.

~~128~~95

FIRSTENERGY SOLUTIONS CORP.

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

~~9. REGULATORY MATTERS~~FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services, 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.

~~(A) RELIABILITY INITIATIVES~~

~~In 2005, Congress amended the Federal Power Act~~FES' revenues are derived from sales to ~~provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply~~individual retail customers, sales 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 Reliability~~First~~ ~~Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst~~ ~~region. FirstEnergy actively participates~~communities in the ~~NERC and ReliabilityFirst~~ ~~stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement~~form 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~~government aggregation programs and the ~~FERC will continue~~sale of electricity to ~~refine existing reliability standards as well as~~affiliated utility companies to ~~develop and adopt new reliability standards. The financial impact of complying with new~~meet all 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.

~~(B) OHIO~~

~~129~~

~~130~~

~~(C) PENNSYLVANIA~~

~~Met-Ed and Penelec purchase~~ a portion of their PLR and default service ~~requirements~~requirements. FES' revenues also include wholesale sales non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois.

The demand for electricity produced and sold by FES, along with the price of that electricity, is impacted by conditions in competitive power markets, global economic activity, economic activity in the Midwest and Mid-Atlantic regions, and weather conditions.

For additional information with respect to FES, please see the information contained in FirstEnergy's Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.

Results of Operations

Net income decreased to $80 million in the first three months of 2010 compared to $171 million in the same period of 2009. The decrease was primarily due to higher purchased power, fuel and interest expense, partially offset by higher revenues and investment income.

Revenues

Total revenues increased $162 million in the first three months of 2010, primarily due to an increase in direct and government aggregation sales volumes and sales of RECs, partially offset by decreases in PLR sales to the Ohio Companies and wholesale sales.

The increase in revenues resulted from the following sources:

	Three Months
	Ended March 31				Increase
Revenues by Type of Service	2010		2009		(Decrease)
	(In millions)

Direct and Government Aggregation	$	512	$	91	$	421
PLR		677		893		(216	)
Wholesale		87		189		(102	)
Transmission		17		25		(8	)
RECs		67		-		67
Other		28		28		-
Total Revenues	$	1,388	$	1,226	$	162

Direct and government aggregation revenues increased $421 million resulting from increased revenue in both the MISO and PJM markets. The increase in revenue is primarily the result of the acquisition of new customers and the inclusion of the transmission-related component in MISO retail rates, partially offset by lower unit prices. The acquisition of new customers is primarily due to new commercial and industrial customers as well as new government aggregation contracts with communities in Ohio that provide generation to approximately one million residential and small commercial customers. During January 2010, FES began supplying power to approximately 425,000 NOPEC customers.

PLR revenues decreased $216 million primarily due to lower KWH sales volumes to the Ohio Companies and lower unit prices, partially offset by increased sales volumes and higher unit prices to the Pennsylvania Companies. The lower sales volumes and unit prices to the Ohio Companies in the first three months of 2010 reflected the results of the May 2009 power procurement processes. The increased revenues to the Pennsylvania Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a ~~fixed-price~~third-party contract and at prices that were slightly higher than in the first quarter of 2009. The increase was partially offset by lower sales to Penn due to decreased default service requirements in 2010 compared to 2009.

Wholesale revenues decreased $102 million due to a 76.3% decline in volume reflecting market declines, partially offset by higher capacity prices.

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

Source of Change in Direct and Government Aggregation	Increase (Decrease)
	(In millions)
Direct Sales:
Effect of 471.5% increase in sales volumes	$	289
Change in prices		(30	)
		259
Government Aggregation:
Effect of an increase in sales volumes		162
Change in prices		-
		162
Net Increase in Direct and Gov’t Aggregation Revenues	$	421

Source of Change in Wholesale Revenues	Increase (Decrease)
	(In millions)
PLR:
Effect of 10.2% decrease in sales volumes	$	(91	)
Change in prices		(125	)
		(216	)
Wholesale:
Effect of 76.3% decrease in sales volumes		(112	)
Change in prices		10
		(102	)
Net Decrease in Wholesale Revenues	$	(318	)

Transmission revenues decreased $8 million primarily due to the inclusion of the transmission-related component in retail rates beginning in mid-2009 as a result of the CBP.

In the first three months of 2010, FES sold $67 million of RECs.

Expenses

Total expenses increased $312 million in the first three months of 2010, compared with the same period of 2009.

The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first three months of 2010, from the same period last year:

Source of Change in Fuel and Purchased Power	Increase (Decrease)
	(In millions)
Fossil Fuel:
Change due to increased unit costs	$	36
Change due to volume consumed		(27	)
		9
Nuclear Fuel:
Change due to increased unit costs		12
Change due to volume consumed		1
		13
Non-affiliated Purchased Power:
Power contract mark-to-market adjustment		52
Change due to decreased unit costs		(62	)
Change due to volume purchased		300
		290
Affiliated Purchased Power:
Change due to increased unit costs		(12	)
Change due to volume purchased		10
		(2	)
Net Increase in Fuel and Purchased Power Costs	$	310

Fossil fuel costs increased $9 million in the first three months of 2010, compared to the same period of 2009, as a result of higher prices, partially offset by reduced volume. The increased costs reflect higher coal transportation charges in the first three months of 2010, compared to the same period last year. Reduced volume reflects lower generation in the first three months of 2010, compared to the same period last year. Nuclear fuel costs increased $13 million, primarily due to the replacement of nuclear fuel at higher unit costs following the refueling outages that occurred in 2009.

Non-affiliated purchased power costs increased $290 million due primarily to higher volumes purchased and a power contract mark-to-market adjustment, partially offset by lower unit costs. The increase in volume primarily relates to the assumption of a 1,300 MW contract from Met-Ed and Penelec.

Other operating expenses decreased $3 million in the first three months of 2010, compared to the same period of 2009, primarily due to lower nuclear operating costs ($21 million), partially offset by increased transmission expenses ($7 million) and increased expenses associated with uncollectible customer accounts and agent fees ($5 million).

Depreciation expense increased $2 million in the first three months of 2010, compared to the same period of 2009 primarily due to increased property additions.

General taxes increased $3 million due to sales taxes associated with increased revenues.

Other Expense

Total other expense decreased $12 million in the first three months of 2010, compared to the same period of 2009, primarily due to a $30 million increase in investment income resulting from reduced impairments in the value of nuclear decommissioning trust investments, partially offset by a $17 million increase in interest expense (net of capitalized interest). Interest expense increased primarily due to new issuances of long-term debt in the second half of 2009 combined with the restructuring of existing long-term debt.

OHIO EDISON COMPANY

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

For additional information with respect to OE, please see the information contained in FirstEnergy's Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk, Credit Risk, Outlook and New Accounting Standards and Interpretations.

Results of Operations

Earnings available to parent increased to $36 million in the first three months of 2010, compared to $12 million in the same period of 2009. The increase primarily resulted from lower purchased power costs and other operating costs, partially offset by lower revenues.

Revenues

Revenues decreased $241 million, or 32.1%, in the first three months of 2010, compared with the same period in 2009, due to a decrease in generation and distribution revenues.

Retail generation revenues decreased $225 million primarily due to a decrease in KWH sales in all customer classes, partially offset by higher average prices in the commercial and industrial classes. Lower KWH sales in all customer classes were primarily the result of a 41.9% increase in customer shopping in the first three months of 2010. Lower KWH sales to residential customers were also due to decreased weather-related usage, reflecting a 3.5% decrease in heating degree days in OE’s service territory. Higher average prices in the commercial and industrial classes, resulted from the CBP auction for the service period beginning June 1, 2009.

Changes in retail generation sales and revenues in the first three months of 2010, from the same period in 2009, are summarized in the following tables:

Retail Generation KWH Sales	Decrease

Residential	(28.1	)%
Commercial	(57.2	)%
Industrial	(65.4	)%
Decrease in Retail Generation Sales	(45.6	)%

Retail Generation Revenues	Decrease
	(In millions)
Residential	$	(78	)
Commercial		(80	)
Industrial		(67	)
Decrease in Retail Generation Revenues	$	(225	)

Distribution revenues decreased $7 million in the first three months of 2010, compared to the same period in 2009, due to lower commercial and industrial revenues, partially offset by higher residential revenues. Commercial and industrial revenues were primarily impacted by lower average unit prices, resulting from lower transmission rates in 2010, partially offset by a PUCO-approved rate increase. Residential distribution revenues were higher due to higher average unit prices resulting from the 2009 ESP, partially offset by lower KWH deliveries resulting from the warmer conditions described above. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major steel customers (18%) and automotive customers (21%).

Changes in distribution KWH deliveries and revenues in the first three months of 2010, from the same period in 2009, are summarized in the following tables:

Distribution KWH Deliveries	Increase (Decrease)

Residential		(2.2	)%
Commercial		(2.1	)%
Industrial		3.4	%
Net Decrease in Distribution Deliveries		(0.6	)%

Distribution Revenues	Increase (Decrease)
	(In millions)
Residential	$	7
Commercial		(3	)
Industrial		(11	)
Net Decrease in Distribution Revenues	$	(7	)

Wholesale revenues decreased $6 million primarily due to lower unit prices, partially offset by an increase in sales to FES for OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.

Expenses

Total expenses decreased $283 million in the first three months of 2010, from the same period of 2009. The following table presents changes from the prior period by expense category:

Expenses – Changes	Increase (Decrease)
		(In millions)
Purchased power costs	$	(222	)
Other operating costs		(69	)
Amortization of regulatory assets, net		9
General taxes		(1	)
Net Decrease in Expenses	$	(283	)

Purchased power costs decreased in the first three months of 2010, compared to the same period of 2009, primarily due to lower KWH purchases resulting from increased customer shopping in the first three months of 2010 and slightly lower unit costs. The decrease in other operating costs for the first three months of 2010, was primarily due to lower MISO transmission expenses (included in the cost of purchased power beginning June 1, 2009) and lower costs associated with regulatory obligations for economic development and energy efficiency programs under OE’s 2009 ESP. Higher amortization of net regulatory assets was primarily due to the recovery of PUCO-approved deferrals that began in 2010.

100

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

For additional information with respect to CEI, please see the information contained in FirstEnergy's Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk, Credit Risk, Outlook and New Accounting Standards and Interpretations.

Results of Operations

Earnings increased to $14 million in the first three months of 2010, compared to a loss of $106 million in the same period of 2009. The increase in earnings was primarily the due to decreased amortization of net regulatory assets, purchased power and other operating costs, partially offset by decreased revenues and deferral of new regulatory assets.

Revenues

Revenues decreased $120 million, or 26.6%, in the first three months of 2010, compared to the same period of 2009, due to decreased retail generation and distribution revenues.

Retail generation revenues decreased $69 million in the first three months of 2010, compared to the same period of 2009, primarily due to lower KWH sales across all customer classes, partially offset by higher average unit prices in all customer classes. Reduced KWH sales were primarily the result of increased customer shopping in the first three months of 2010. Lower KWH sales to residential customers also resulted from decreased weather-related usage, reflecting a 9.2% decrease in heating degree days. Retail generation prices increased in 2010 as a result of the CBP auction for the service period beginning June 1, 2009.

Changes in retail generation sales and revenues in the first three months of 2010, compared to the same period of 2009, are summarized in the following tables:


Retail Generation KWH Sales	Decrease

Residential		(53.2	)%
Commercial		(66.2	)%
Industrial		(46.2	)%
Decrease in Retail Generation Sales		(53.6	)%

Retail Generation Revenues	Decrease
	(In millions)
Residential	$	(17	)
Commercial		(33	)
Industrial		(19	)
Decrease in Retail Generation Revenues	$	(69	)

Distribution revenues decreased $43 million in the first three months of 2010, compared to the same period of 2009, due to lower average unit prices for all customer classes and decreased KWH deliveries in the residential sector, partially offset by increased KWH deliveries in the industrial sector. The lower average unit prices were the result of lower transition rates in 2010, partially offset by a PUCO-approved distribution rate increase effective May 1, 2009. Lower KWH sales in the residential sector were the result of the warmer weather described above. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major steel customers (134%) and automotive customers (13%).

101

Changes in distribution KWH deliveries and revenues in the first three months of 2010, compared to the same period of 2009, are summarized in the following tables:

Distribution KWH Deliveries	Increase (Decrease)

Residential		(3.9	)%
Commercial		(0.6	)%
Industrial		10.9	%
Net Increase in Distribution Deliveries		2.6	%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(5	)
Commercial		(13	)
Industrial		(25	)
Decrease in Distribution Revenues	$	(43	)

Expenses

Total expenses decreased $314 million in the first three months of 2010, compared to the same period of 2009. The following table presents the change from the prior period by expense category:

Expenses - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	(164	)
Other operating costs		(33	)
Amortization of regulatory assets		(212	)
Deferral of new regulatory assets		95
Net Decrease in Expenses	$	(314	)

Purchased power costs decreased in the first three months of 2010, primarily due to lower KWH sales requirements as discussed above. Other operating costs decreased due to lower transmission expenses (included in the cost of purchased power beginning June 1, 2009), labor and employee benefit expenses and reduced regulatory obligations for economic development and energy efficiency programs. Decreased amortization of regulatory assets was due primarily to the 2009 impairment of CEI’s Extended RTC regulatory asset of $216 million in accordance with the PUCO-approved ESP. A decrease in the deferral of new regulatory assets was primarily due to CEI’s contemporaneous recovery of purchased power costs in 2010.

102

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 procures generation services for those customers electing to retain TE as their power supplier.

For additional information with respect to TE, please see the information contained in FirstEnergy's Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.

Results of Operations

Earnings available to parent increased to $8 million in the first three months of 2010, compared to $1 million in the same period of 2009. The increase was primarily due to decreased net amortization of regulatory assets, purchased power and other operating costs, partially offset by a decrease in revenues and an increase in interest expense.

Revenues

Revenues decreased $112 million, or 46%, in the first three months of 2010, compared to the same period of 2009, primarily due to lower retail generation and distribution revenues, partially offset by an increase in wholesale generation revenues.

Retail generation revenues decreased $105 million in the first three months of 2010, compared to the same period of 2009, primarily due to lower KWH sales across all customer classes and lower unit prices to industrial customers. Lower KWH sales to all customer classes were primarily due to increased customer shopping. Lower KWH sales for residential customers also resulted from decreased weather-related usage, reflecting a 7.5% decrease in heating degree days in the first three months of 2010. Lower unit prices for industrial customers are primarily due to the absence of TE’s fuel cost recovery rider that was effective from January through May 2009, partially offset by increased generation prices resulting from the CBP auction, effective June 1, 2009.

Changes in retail electric generation KWH sales and revenues in the first three months of 2010 from the same period of 2009 are summarized in the following tables:

Retail Generation KWH Sales	Decrease

Residential		(47.9	)%
Commercial		(69.8	)%
Industrial		(57.7	)%
Decrease in Retail Generation Sales		(57.9	)%

Retail Generation Revenues	Decrease
	(In millions)
Residential	$	(24	)
Commercial		(35	)
Industrial		(46	)
Decrease in Retail Generation Revenues	$	(105	)

Distribution revenues decreased $13 million in the first three months of 2010, compared to the same period of 2009, primarily due to lower unit prices for all customer classes, partially offset by increased KWH deliveries to industrial customers. Lower unit prices for all customer classes are primarily due to lower transmission rates. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major automotive customers (14%) and steel customers (37%).

103

Changes in distribution KWH deliveries and revenues in the first three months of 2010, compared to the same period of 2009, are summarized in the following tables:

Distribution KWH Deliveries	Increase (Decrease)

Residential		(2.4	)%
Commercial		(2.6	)%
Industrial		13.9	%
Net Increase in Distribution Deliveries		4.7	%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(2	)
Commercial		(3	)
Industrial		(8	)
Decrease in Distribution Revenues	$	(13	)

Wholesale revenue increased $4 million in the first three months of 2010, compared to the same period of 2009, primarily due to higher revenues from associated sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.

Expenses

Total expenses decreased $131 million in the first three months of 2010, compared to the same period of 2009. The following table presents changes from the prior period by expense category:

Expenses – Changes	Decrease
	(In millions)
Purchased power costs	$	(93	)
Amortization (deferral) of regulatory assets, net		(18	)
Other operating costs		(19	)
General taxes		(1	)
Decrease in Expenses	$	(131	)

Purchased power costs decreased $93 million in the first three months of 2010, compared to the same period of 2009 due to lower volume as a result of decreased KWH sales requirements. The $18 million decrease in amortization (deferral) of net regulatory assets was primarily due to an increase in PUCO-approved cost deferrals, lower MISO transmission cost amortization, partially offset by the absence of MISO transmission and fuel cost deferrals in the first three months of 2010, compared to the same period of 2009. Other operating costs decreased $19 million primarily due to reduced transmission expense (included in the cost of power purchased from others beginning June 1, 2009), lower costs associated with regulatory obligations for economic development and energy efficiency programs and decreased labor and employee benefit expenses. The decrease in general taxes was primarily due to lower Ohio KWH taxes as a result of the reduced KWH deliveries discussed above.

Other Expense

Other expense increased $7 million in the first three months of 2010, compared to the same period of 2009, primarily due to higher interest expense associated with the April 2009 issuance of $300 million senior secured notes.

104

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also procures generation services for 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.

For additional information with respect to JCP&L, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Outlook, Market Risk and New Accounting Standards and Interpretations.

Results of Operations

Net income increased to $29 million in the first three months of 2010, compared to $28 million in the same period of 2009. The increase was primarily due to lower purchased power costs and decreased amortization of regulatory assets, partially offset by lower revenues and increased other operating costs.

Revenues

In the first three months of 2010, revenues decreased $70 million, or 9%, compared to the same period of 2009. The decrease in revenues is primarily due to a decrease in retail and wholesale generation revenues and distribution throughput revenues.

In the first three months of 2010, retail generation revenues decreased $56 million due to lower retail generation KWH sales in all sectors, partially offset by higher unit prices in the residential and commercial sectors. Lower sales to the commercial and industrial sector were primarily due to an increase in the number of shopping customers. Lower KWH sales to the residential sector reflected decreased weather-related usage due to an 8.7% decrease in heating degree days in the first three months of 2010 compared to the same period of 2009.

Changes in retail generation KWH sales and revenues by customer class in the first three months of 2010 compared to the same period of 2009 are summarized in the following tables:

Retail Generation KWH Sales	Decrease

Residential		(1.5	)%
Commercial		(36.0	)%
Industrial		(25.7	)%
Decrease in Generation Sales		(16.0	)%

Retail Generation Revenues	Increase (Decrease)
	(In millions)
Residential	$	3
Commercial		(55	)
Industrial		(4	)
Net Decrease in Generation Revenues	$	(56	)

Wholesale generation revenues decreased $11 million in the first three months of 2010 compared to the same period of 2009 due to a decrease in sales volume resulting from reduced available power for sale due to the termination of a NUG power purchase contract in July 2009.

Distribution revenues decreased $5 million in the first three months of 2010 compared to the same period of 2009 due to lower KWH deliveries, reflecting milder weather in JCP&L’s service territory, and a decrease in composite unit prices in the commercial and industrial sectors.

105

Changes in distribution KWH deliveries and revenues by customer class in the first three months of 2010 compared to the same period of 2009 are summarized in the following tables:

Distribution KWH Deliveries	Increase (Decrease)

Residential		(1.5	)%
Commercial		(1.6	)%
Industrial		1.3	%
Net Decrease in Distribution Deliveries		(1.2	)%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(2	)
Commercial		(3	)
Industrial		-
Decrease in Distribution Revenues	$	(5	)

Expenses

Total expenses decreased $73 million in the first three months of 2010 compared to the same period of 2009. The following table presents changes from the prior period by expense category:

Expenses - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	(67	)
Other operating costs		9
Provision for depreciation		3
Amortization of regulatory assets, net		(17	)
General taxes		(1	)
Net Decrease in Expenses	$	(73	)

Purchased power costs decreased in the first three months of 2010 primarily due to the lower KWH sales requirements and termination of a NUG contract as discussed above. Other operating costs increased in the first three months of 2010 primarily due to higher labor and tree trimming expenses related to major storms in JCP&L’s service territory. Depreciation expense increased due to an increase in depreciable property since the first quarter of 2009. Amortization of regulatory assets decreased in the first three months of 2010 primarily due to deferral of the major storm costs. General taxes decreased principally due to taxes assessed on a lower revenue base.

106

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 procures generation service for those customers electing to retain Met-Ed as their power supplier. Met-Ed has a 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~~with FES, to ~~provide~~supply nearly all of its energy requirements 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,~~For additional information with respect to Met-Ed, please see the information contained in FirstEnergy's Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Outlook, Market Risk and New Accounting Standards and Interpretations.

Results of Operations

Net income decreased to $12 million in the first three months of 2010, compared to $17 million in the same period of 2009. The decrease was primarily due to increased purchased power costs and amortization of net regulatory assets, partially offset by an increase in distribution and generation revenues.

Revenues

Revenues increased by $43 million, or 10%, in the first three months of 2010 compared to the same period of 2009 primarily due to higher distribution and generation revenues, partially offset by a decrease in transmission revenues.

Distribution revenues increased $24 million in the ~~PPUC approved~~first three months of 2010, compared to the same period of 2009, primarily due to higher transmission rates, resulting from the annual update to Met-Ed’s ~~and Penelec’s annual updates to their~~ TSC rider ~~for the period~~effective June 1, 2009, ~~through May 31, 2010, as required in connection with~~partially offset by lower CTC rates for the ~~PPUC’s January 2007 rate order. For Penelec’s~~residential class resulting from a PPUC-approved NUG Statement Compliance filing. Lower KWH deliveries to residential customers ~~the new TSC resulted in an approximate 1%~~reflect reduced weather-related usage due to a 7.3% 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-Edheating degree days in the ~~previous year and to reflect updated projected costs. In order to gradually transition customers~~first three months of 2010, compared to the ~~higher rate,~~same period of 2009. Higher industrial KWH deliveries were due to the ~~PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed~~recovering economy.

Changes in distribution KWH deliveries and revenues in the ~~PPUC’s May 2008 Order and defer $57.5 million~~first three months of ~~projected costs~~2010 compared 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 same period ~~June~~of 2009 ~~through May 2010.~~

~~On October 15, 2008,~~are summarized in 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:following tables:

·	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;	Increase
Distribution KWH Deliveries		(Decrease)

Residential			(5.4	)%
Commercial			(1.9	)%
Industrial			2.4	%
Net Decrease in Distribution Deliveries			(2.5	)%

· Distribution Revenues	~~the competitive procurement process must be approved by the PPUC and may include auctions, RFPs, and/or bilateral agreements;~~	Increase
		(In millions)
Residential		$	7
Commercial			10
Industrial			7
Increase in Distribution Revenues		$	24

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

Wholesale revenues increased $22 million in the first three months of 2010 compared to the same period of 2009, primarily reflecting higher PJM spot market prices.

~~131~~107

Retail generation revenues increased $3 million in the first three months of 2010, compared to the same period of 2009, due primarily to higher composite unit prices in the residential and commercial customer classes and higher KWH sales to the industrial customer class. This increase was partially offset by lower KWH sales to the residential and commercial customer classes.

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

Changes in retail generation sales and revenues in the first three months of 2010, compared to the same period of 2009, are summarized in the following tables:

·	~~utilities must reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and~~	Increase
Retail Generation KWH Sales		(Decrease)

Residential			(5.4	)%
Commercial			(1.9	)%
Industrial			2.4	%
Net Decrease in Retail Generation Sales			(2.5	)%

·	~~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~~

~~133~~

~~Post Transition Period Rate Design~~

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

~~134~~

~~MISO Resource Adequacy Proposal~~

~~FES Sales to Affiliates~~

~~135~~

~~10. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS~~

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

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

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

~~SFAS 168 – “The~~ ~~FASB Accounting Standards Codification~~TM ~~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 Codification~~TM (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.

~~136~~

~~11. SEGMENT INFORMATION~~

FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The assets and revenues for all other business operations are below the quantifiable threshold for operating segments for separate disclosure as "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 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 electricity sales primarily in Ohio, Pennsylvania, Maryland and Michigan, owns or leases and operates FirstEnergy's generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment's customers. The segment's internal revenues represent sales to its affiliates in Ohio and Pennsylvania.

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

~~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

~~138~~

	~~12. SUPPLEMENTAL GUARANTOR INFORMATION~~	Increase
Retail Generation Revenues		(Decrease)
		(In millions)
Residential		$	3
Commercial			(1	)
Industrial			1
Net Increase in Retail Generation Revenues		$	3

~~On July 13, 2007, FGCO completed a sale~~

Transmission revenues decreased $6 million in the first three months of 2010 compared to the same period of 2009 primarily due to decreased revenues related to Met-Ed’s Financial Transmission Rights. Met-Ed defers the difference between transmission revenues and ~~leaseback transaction for its 93.825% undivided interest~~transmission costs incurred, resulting in ~~Bruce Mansfield Unit 1. FES has fully, unconditionally and irrevocably guaranteed all~~no material effect to current period earnings.

Expenses

Total operating expenses increased $46 million in the first three months of ~~FGCO's obligations under each~~2010 compared to the same period of 2009. The following table presents changes from the ~~leases. The related lessor notes and pass through certificates are not guaranteed~~prior year by ~~FES or FGCO, but~~expense category:

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	29
Other operating costs		(4	)
Amortization of regulatory assets, net		21
Net Increase in Expenses	$	46

Purchased power costs increased $29 million in the ~~notes are secured~~first three months of 2010 due to an increase in unit costs, partially offset by among other things, each lessor trust's undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES' lease guaranty. This transaction is classified as an operating lease under GAAP for FES and FirstEnergy andreduced volumes purchased as a ~~financing for FGCO.~~result of lower KWH sales requirements. The net amortization of regulatory assets increased $21 million in the first three months of 2010 compared to the same period of 2009 primarily due to increased transmission cost recovery. Other operating costs decreased $4 million in the first three months of 2010 primarily due to lower employee benefit expenses.

The condensed consolidating statements of income for the three-month and six-month periods ended June 30, 2009 and 2008, consolidating balance sheets as of June 30, 2009 and December 31, 2008 and consolidating statements of cash flows for the six months ended June 30, 2009 and 2008 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES' investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.Other Expense

Other expense increased in the first three months of 2010 primarily due to a decrease in interest earned on regulatory assets, reflecting a lower regulatory asset base.

~~139~~108

PENNSYLVANIA ELECTRIC COMPANY

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

MANAGEMENT'S NARRATIVE

~~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

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 procures generation services for those customers electing to retain Penelec as their power supplier. Penelec has a partial requirements wholesale power sales agreement with FES, to supply nearly all of its energy requirements at fixed prices through 2010.

For additional information with respect to Penelec, please see the information contained in FirstEnergy's Management’s Discussion and Analysis of Financial Condition and Results of Operations above the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk, Outlook and New Accounting Standards and Interpretations.

Results of Operations

Net income decreased to $17 million in the first three months of 2010, compared to $19 million in the same period of 2009. The decrease was primarily due to higher purchased power costs, partially offset by higher revenues and decreases in the amortization (deferral) of net regulatory assets, other operating costs and general taxes.

Revenues

In the first three months of 2010, revenues increased $15 million, or 4%, compared to the same period of 2009. The increase in revenue is primarily due to higher wholesale and retail generation revenues, partially offset by lower distribution and transmission revenues.

Wholesale revenues increased $18 million in the first three months of 2010, compared to the same period of 2009, primarily reflecting higher PJM capacity prices.

Retail generation revenues increased $16 million in the first three months of 2010, compared to the same period of 2009, primarily due to higher unit prices in all customer classes and higher KWH sales to the commercial and industrial customer classes, partially offset by decreased KWH sales to the residential customer class. Higher unit prices across all customer classes are primarily due to an increase in the generation rate resulting from the PPUC-approved NUG Statement Compliance filing, effective January 1, 2010. Higher KWH sales to commercial and industrial customers are due to improving economic conditions in Penelec’s service territory. Lower KWH sales to residential customers are due to decreased weather-related usage, reflecting a 6.1% decrease in heating degree day s in the first three months of 2010.

Changes in retail generation sales and revenues in the first three months of 2010 compared to the same period of 2009 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)

Residential		(1.1	)%
Commercial		0.7	%
Industrial		3.1	%
Net increase in Retail Generation Sales		0.6	%


Retail Generation Revenues	Increase
	(In millions)
Residential	$	3
Commercial		6
Industrial		7
Increase in Retail Generation Revenues	$	16

~~147~~109

Distribution revenues decreased by $11 million in the first three months of 2010, compared to the same period of 2009, primarily due to a decrease in the transition rate in all customer classes resulting from the PPUC-approved NUG Statement Compliance filing, partially offset by an increase in the universal service rate for the residential customer class.

Changes in distribution KWH deliveries and revenues in the first three months of 2010, compared to the same period of 2009, are summarized in the following tables:

Distribution KWH Deliveries	Increase (Decrease)

Residential		(1.1	)%
Commercial		0.7	%
Industrial		3.8	%
Net increase in Distribution Deliveries		0.9	%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(1	)
Commercial		(6	)
Industrial		(4	)
Decrease in Distribution Revenues	$	(11	)

Transmission revenues decreased by $4 million in the first three months of 2010, compared to the same period of 2009, 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.

Expenses

Total operating expenses increased by $9 million in the first three months of 2010, as compared with the same period of 2009. The following table presents changes from the prior period by expense category:

Expenses - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	37
Amortization (deferral) of regulatory assets, net		(19	)
Other operating costs		(5	)
General taxes		(4	)
Net Increase in Expenses	$	9

Purchased power costs increased $37 million in the first three months of 2010, compared to the same period of 2009, primarily due to higher unit costs. The amortization (deferral) of net regulatory assets decreased $19 million in the first three months of 2010, primarily due to increased cost deferrals resulting from higher transmission expenses and decreased amortization of regulatory assets resulting from lower CTC revenues. Other operating costs decreased $5 million in the first three months of 2010, primarily due to reduced labor and employee benefit expenses. General taxes decreased $4 million primarily due to a favorable ruling on a property tax appeal.

Other Expense

In the first three months of 2010, other expense increased $3 million primarily due to an increase in interest expense on long-term debt, partially offset by lower interest expense on short-term borrowings.

110

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See "Management's Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Information" in Item 2 above.

ITEM 4. CONTROLS AND PROCEDURES

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY

FirstEnergy's management, with the participation of its chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15(d)-15(e), 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~~the chief executive officer and chief financial officer have concluded that the 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,~~March 31, 2010, 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 management, with the participation of its chief executive officer and chief financial officer, have reviewed and evaluated the effectiveness of such registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15(d)-15(e), 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~~each registrant’s chief executive officer and chief financial officer 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,~~March 31, 2010, there were no changes in the registrants' internal control over financial reporting that ~~have~~has materially affected, or ~~are~~is reasonably likely to materially affect, the registrants' internal control over financial reporting.

~~148~~111

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~~includes a detailed discussion of its risk factors. ~~For the quarter ended June 30, 2009, there~~There have been no material changes to these risk ~~factors.~~factors for the quarter ended March 31, 2010.

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~~first quarter of ~~2009.~~2010.

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.

		Period
		January	February	March	First Quarter
Total Number of Shares Purchased (a)		64,186	188,695	1,184,918	1,437,799
Average Price Paid per Share		$45.35	$39.56	$39.06	$39.41
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 commonstock 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 De ferred Compensation Plan.

ITEM ~~4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS~~5. OTHER INFORMATION

~~(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):

Number of Votes
Broker
For Against Abstentions Non-Votes

155,741,944 36,909,437 2,395,715 27,939,083

~~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):

Number of Votes
Broker
For Against Abstentions Non-Votes

110,529,850 82,017,229 2,499,618 27,939,482

~~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):

Number of Votes
Broker
For Against Abstentions Non-Votes

88,329,182 103,545,248 3,172,666 27,939,083

~~(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):

Number of Votes
Broker
For Against Abstentions Non-Votes

128,558,349 64,162,961 2,325,387 27,939,482

~~Based on this result, the Board of Directors will further review this proposal.~~

~~150~~

None

ITEM 6. EXHIBITS

Exhibit Number


FirstEnergy
	~~10.1~~2.1	Agreement and Plan of Merger, dated as of February 10, 2010, by and among FirstEnergy Corp., Element Merger Sub, Inc. and Allegheny Energy, Inc. (incorporated by reference to FirstEnergy’s Form ~~of Written Consent for Named Executive Officers dated June 1, 2009~~8-K filed February 11, 2010, Exhibit 2.1, File No. 333-21011)
	12	Fixed charge ratios
		15		~~Letter from independent registered public accounting firm~~
		~~31.1~~		~~Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)~~
		~~31.2~~		~~Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)~~
		32		~~Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350~~
		101*		The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the 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~~
~~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~~
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
	101*	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended March 31, 2010, 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.
		Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Registrant will furnish the omitted schedules to the Securities and Exchange Commission upon request by the Commission.

112

FES
	~~(A)~~ 12	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.Fixed charge ratios
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
OE
	12	Fixed charge ratios
	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
~~(B)~~ CEI		~~Three substantially similar agreements, each dated~~
	12	Fixed charge ratios
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of ~~the same date, were executed~~chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and ~~delivered by the registrant~~chief financial officer, pursuant to 18 U.S.C. Section 1350
TE
	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 ~~its affiliates with respect~~chief financial officer, pursuant to ~~three other series~~18 U.S.C. Section 1350
JCP&L
	12		Fixed charge ratios
	31.1		Certification of ~~pollution control revenue refunding bonds issued by the Ohio Water Development Authority~~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 ~~the Beaver County Industrial Development Authority relating~~chief financial officer, pursuant to ~~pollution control notes~~18 U.S.C. Section 1350
Met-Ed
	12		Fixed charge ratios
	31.1		Certification of ~~FirstEnergy Generation Corp.~~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 ~~FirstEnergy Nuclear Generation Corp.~~chief financial officer, pursuant to 18 U.S.C. Section 1350
Penelec
	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

* 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, FES, 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.

~~154~~113

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.

~~August 3, 2009~~May 4, 2010

	FIRSTENERGY CORP.
	Registrant

	FIRSTENERGY SOLUTIONS CORP.
	Registrant

	OHIO EDISON COMPANY
	Registrant

	THE CLEVELAND ELECTRIC
	ILLUMINATING COMPANY
	Registrant

	THE TOLEDO EDISON COMPANY
	Registrant

	METROPOLITAN EDISON COMPANY
	Registrant

	PENNSYLVANIA ELECTRIC COMPANY
	Registrant

	/s/ Harvey L. Wagner
	Harvey L. Wagner
	Vice President, Controller
	and Chief Accounting Officer

	JERSEY CENTRAL POWER & LIGHT COMPANY
	Registrant



	/s/ ~~Paulette~~Kevin R. ~~Chatman~~Burgess
	~~Paulette~~Kevin R. ~~Chatman~~Burgess
	Controller
	(Principal Accounting Officer)

~~155~~114

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., 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
~~Yes~~ ~~( )~~ No ~~(X)~~	~~FirstEnergy Solutions Corp.~~

Large Accelerated Filer (X)	FirstEnergy Corp.
Accelerated Filer ( )	N/A
Non-accelerated Filer (Do not check if a smaller reporting company) (X)	FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company

	OUTSTANDING
CLASS	AS OF ~~August 3, 2009~~APRIL 30, 2010
FirstEnergy Corp., ~~$0.10~~$.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

~~Jersey Central Power & Light Company~~		~~Pages~~
	19
	~~Management's Narrative Analysis of Results of Operations~~	~~76-77~~
	~~Report of Independent Registered Public Accounting Firm~~	78
	~~Consolidated Statements of Income and Comprehensive Income~~	79
	~~Consolidated Balance Sheets~~	80
	~~Consolidated Statements of Cash Flows~~	81

Metropolitan Edison Company

	~~Management's Narrative Analysis of Results of Operations~~	~~82-83~~
	~~Report of Independent Registered Public Accounting Firm~~	84
	Consolidated Statements of Income and Comprehensive Income (Loss)	8520
	Consolidated Balance Sheets	8621
	Consolidated Statements of Cash Flows	87

~~Pennsylvania Electric Company~~ 22

Pennsylvania Electric Company			~~Management's Narrative Analysis of Results of Operations~~	~~88-89~~
	~~Report of Independent Registered Public Accounting Firm~~	90
	Consolidated Statements of Income and Comprehensive Income (Loss)	9123
	Consolidated Balance Sheets	9224
	Consolidated Statements of Cash Flows	9325

		Pages

Glossary of Terms		~~iii-v~~

~~Part I. Financial Information~~iii-iv

~~Items~~Item 1. ~~and 2. -~~ Financial Statements ~~and Management's Discussion and Analysis ofFinancial Condition and Results of Operations.~~

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	461
	Consolidated Statements of Comprehensive Income	472
	Consolidated Balance Sheets	483
	Consolidated Statements of Cash Flows	494

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	555
	Consolidated Balance Sheets	566
	Consolidated Statements of Cash Flows	577

Ohio Edison Company

	~~Management's Narrative Analysis of Results of Operations~~	~~58-59~~
	~~Report of Independent Registered Public Accounting Firm~~	60
	Consolidated Statements of Income and Comprehensive Income (Loss)	618
	Consolidated Balance Sheets	629
	Consolidated Statements of Cash Flows	6310

The Cleveland Electric Illuminating Company

	~~Management's Narrative Analysis of Results of Operations~~	~~64-65~~
	~~Report of Independent Registered Public Accounting Firm~~	66
	Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)	6711
	Consolidated Balance Sheets	6812
	Consolidated Statements of Cash Flows	6913

The Toledo Edison Company

	~~Management's Narrative Analysis~~Consolidated Statements of ~~Results of Operations~~Income and Comprehensive Income (Loss)	~~70-71~~14
	~~Report~~Consolidated Balance Sheets	15
	Consolidated Statements of ~~Independent Registered Public Accounting Firm~~Cash Flows	7216

Jersey Central Power & Light Company

	Consolidated Statements of Income and Comprehensive Income	7317
	Consolidated Balance Sheets	7418
	Consolidated Statements of Cash Flows	75

		Pages

Combined Notes To Consolidated Financial Statements		26-62

Item 2. Management's Discussion and Analysis of Registrant and Subsidiaries		~~94-109~~63-95

~~Combined Notes to Consolidated Financial Statements~~Management's Narrative Analysis of Results of Operations		~~110-147~~

FirstEnergy Solutions Corp.		96-98
Ohio Edison Company		99-100
The Cleveland Electric Illuminating Company		101-102
The Toledo Edison Company		103-104
Jersey Central Power & Light Company		105-106
Metropolitan Edison Company		107-108
Pennsylvania Electric Company		109-110

Item 3. Quantitative and Qualitative Disclosures About Market ~~Risk.~~Risk		~~148~~111

Item 4. Controls and Procedures – ~~FirstEnergy.~~FirstEnergy		~~148~~111

Item 4T. Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and ~~Penelec.~~Penelec		~~148~~111

Part II. Other Information

Item 1. Legal ~~Proceedings.~~Proceedings		~~149~~112

Item 1A. Risk ~~Factors.~~Factors		~~149~~112

Item 2. Unregistered Sales of Equity Securities and Use of ~~Proceeds.~~Proceeds		~~149~~112

Item ~~4. Submission of Matters to a Vote of Security Holders.~~5. Other Information		~~149-150~~112

Item 6. ~~Exhibits.~~Exhibits		~~151-154~~112-113

ATSI	American Transmission Systems, Incorporated, owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
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	FirstEnergy, OE, CEI, TE, JCP&L, Met-Ed and Penelec
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak	A joint venture between FirstEnergy Ventures Corp. and Boich Companies, that owns mining and coal transportation operations near Roundup, Montana
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
Utilities	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
Waverly	The Waverly Power and Light Company, a wholly owned subsidiary of Penelec

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

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
ARO	Asset Retirement Obligation
BGS	Basic Generation Service
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAVR	Clean Air Visibility Rule
CBP	Competitive Bid Process
CMEC	Capacity market Evolution Committee
CO2	Carbon ~~Dioxide~~dioxide
CTC	Competitive Transition Charge
DOE	United States Department of Energy
DOJ	United States Department of Justice
DCPD	Deferred Compensation Plan for Outside Directors
DPA	Department of the Public Advocate, Division of Rate Counsel (New Jersey)
ECAR	East Central Area Reliability Coordination Agreement
EDCP	Executive Deferred Compensation Plan
EE&C	Energy Efficiency and Conservation
EMP	Energy Master Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
EPRI	Electric Power Research Institute

ESOP	Employee Stock Ownership Plan
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"~~

FMB	First Mortgage Bond
~~FSP~~FPA	~~FASB Staff Position~~Federal Power Act
~~FSP FAS 115-2 and~~ ~~FAS 124-2~~ FRR	~~FSP FAS 115-2 and FAS 124-2, "Recognition and Presentation of Other-Than-Temporary~~ ~~Impairments"~~
~~FSP FAS 132(R)-1~~	~~FSP FAS 132(R)-1, "Employers' Disclosures about Postretirement Benefit Plan Assets"~~
~~FSP FAS 157-4~~	~~FSP FAS 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or~~ ~~Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly"~~ Fixed Resource Requirement
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
~~ICE~~IBEW	~~Intercontinental Exchange~~International Brotherhood of Electrical Workers
IFRS	International Financial Reporting Standards
IRS	Internal Revenue Service
JCARR	Joint Committee on Agency Review
kV	Kilovolt
KWH	Kilowatt-hours
LED	Light-emitting Diode
LIBOR	London Interbank Offered Rate
LOC	Letter of Credit
LTIP	Long-Term Incentive Plan
MACT	Maximum Achievable Control Technology
MISO	Midwest Independent Transmission System Operator, Inc.
Moody's	Moody's Investors Service, Inc.
MRO	Market Rate Offer
MW	Megawatts
MWH	Megawatt-hours
NAAQS	National Ambient Air Quality Standards
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
NNSR	Non-Attainment New Source Review
NOPEC	Northeast Ohio Public Energy Council
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~~OCC	~~New York Mercantile Exchange~~Ohio Consumers’ Counsel
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
OVEC	Ohio Valley Electric Corporation
PCRB	Pollution Control Revenue Bond
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort; an electric utility's obligation to provide generation service to customers whose alternative supplier fails to deliver service
PPUC	Pennsylvania Public Utility Commission
PSA	Power Supply Agreement
PSD	Prevention of Significant Deterioration
PUCO	Public Utilities Commission of Ohio
QSPE	Qualifying Special-Purpose Entity
RCP	Rate Certainty Plan
RECs	Renewable Energy Credits
RFP	Request for Proposal
RPM	Reliability Pricing Model
RTEP	Regional Transmission Expansion Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
S&P	Standard & Poor's Ratings Service
SB221	Amended Substitute Senate Bill 221
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
~~SFAS~~	~~Statement of Financial Accounting Standards~~
~~SFAS 71~~	~~SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"~~
~~SFAS 107~~	~~SFAS No. 107, "Disclosure about Fair Value of Financial Instruments"~~
~~SFAS 115~~	~~SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities"~~
~~SFAS 133~~	~~SFAS No. 133, "Accounting for Derivative Instruments and Hedging 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 157~~	~~SFAS No. 157, "Fair Value Measurements"~~
~~SFAS 160~~	~~SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements – an Amendment~~ ~~of ARB No. 51"~~
~~SFAS 166~~	~~SFAS No. 166, “Accounting for Transfers of Financial Assets – an 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 Codification~~TM ~~and the Hierarchy of Generally~~ ~~Accepted Accounting Principles – a replacement of FASB Statement No. 162”~~
SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
SRECs	Solar Renewable Energy Credits
TBC	Transition Bond Charge
TMI-2	Three Mile Island Unit 2
TSC	Transmission Service Charge
VERO	Voluntary Enhanced Retirement Option
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

	Three Months Ended June 30									Six Months Ended June 30
							Increase									Increase
	2009			2008			(Decrease)			2009			2008			(Decrease)
	(In millions, except per share data)
Earnings By Business Segment:
Energy delivery services	$	133		$	193		$	(60	)	$	91		$	372		$	(281	)
Competitive energy services		276			66			210			431			153			278
Ohio transitional generation services		21			20			1			45			43			2
Other and reconciling adjustments*		(16	)		(16	)		-			(34	)		(29	)		(5	)
Total	$	414		$	263		$	151		$	533		$	539		$	(6	)

Basic Earnings Per Share	$	1.36		$	0.86		$	0.50		$	1.75		$	1.77		$	(0.02	)
Diluted Earnings Per Share	$	1.36		$	0.85		$	0.51		$	1.75		$	1.75		$	-

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

	Three Months
	Ended June 30
Revenues by Type of Service	2009		2008		Decrease
	(In millions)
Distribution services	$	813	$	919	$	(106)
Generation sales:
Retail		718		772		(54)
Wholesale		162		252		(90)
Total generation sales		880		1,024		(144)
Transmission		188		196		(8)
Other		43		43		-
Total Revenues	$	1,924	$	2,182	$	(258)

~~Electric Distribution KWH Deliveries~~
~~Residential~~	~~(2.8~~	)%
~~Commercial~~	~~(3.8~~	)%
~~Industrial~~	~~(20.8~~	)%
~~Total Distribution KWH Deliveries~~	~~(9.4~~	)%

Sources of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 9.5 % decrease in sales volumes	$	(73	)
Change in prices		19
		(54	)
Wholesale:
Effect of 12.7 % decrease in sales volumes		(32	)
Change in prices		(58	)
		(90	)
Net Decrease in Generation Revenues	$	(144	)

Source of Change in Non-Affiliated Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 58.7 % decrease in sales volumes	$	(91	)
Change in prices		20
		(71	)
Wholesale:
Effect of 36.2 % decrease in sales volumes		(61	)
Change in prices		13
		(48	)
Net Decrease in Non-Affiliated Generation Revenues	$	(119	)

Source of Change in Affiliated Generation Revenues	Increase (Decrease)
	(In millions)
Ohio Companies:
Effect of 13.2 % decrease in sales volumes	$	(74	)
Change in prices		201
		127
Pennsylvania Companies:
Effect of 10 % increase in sales volumes		15
Change in prices		(7	)
		8
Net Increase in Affiliated Generation Revenues	$	135

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

	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	)

~~Electric Distribution KWH Deliveries~~
~~Residential~~			~~(1.3) %~~
~~Commercial~~			~~(3.9) %~~
~~Industrial~~			~~(19.2) %~~
~~Total Distribution KWH Deliveries~~			~~(8.0) %~~

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.

	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

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	)

	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	)

	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	)

	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

	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.

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

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

	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	-	-	-	-

	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

Number of Votes
For	Against	Abstentions

219,754,593	2,100,019	1,131,567

Number of Votes

Abstentions