The increase in non-cash charges is primarily due to lower deferrals of new regulatory assets and purchased power costs and higher deferred income taxes. The deferral of new regulatory assets decreased primarily as a result of the Ohio Companies’ transmission and fuel recovery riders that became effective in July 2007 and January 2008, respectively, and the absence of the deferral of decommissioning costs related to the Saxton nuclear research facility in the first quarter of 2007. Lower deferrals of purchased power costs reflected a decrease in NUG costs deferred. The change in deferred income taxes is primarily due to additional tax depreciation as provided for under the Economic Stimulus Act of 2008, the settlement of tax positions taken on federal returns in prior years, and the absence of deferred income tax impacts related to the Bruce Mansfield Unit 1 sale and leaseback transaction in 2007. The changes in working capital and other primarily resulted from higher fossil fuel inventories and increased tax payments, partially offset by a change in the collection of receivables.

~~Cash Flows from Financing Activities~~

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

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

In the first nine months of 2008, cash provided from financing activities was $914 million compared to cash used of $1.4 billion in the first nine months of 2007. The increase was due to higher short-term borrowings primarily for capital expenditures for environmental compliance and to fund a number of strategic acquisitions, including the Fremont Plant ($275 million), Signal Peak ($125 million), and the purchase of lessor equity interests in Beaver Valley Unit 2 and Perry ($438 million). The absence of the repurchase of common stock in the first nine months of 2007 also contributed to the increase in the 2008 period. The following table summarizes security issuances and redemptions or repurchases during the nine months ended September 30, 2008, and 2007.

Nine Months Ended
Securities Issued or September 30,
Redeemed / Repurchased
2008 2007
(In millions)
New issues
Pollution control notes $ 611 $ -
Unsecured notes 20 1,100
$ 631 $ 1,100
Redemptions / Repurchases
First mortgage bonds $ 1 $ 287
Pollution control notes 534 4
Senior secured notes 23 203
Unsecured notes 175 153
Common stock - 918
$ 733 $ 1,565
Short-Term Borrowings

FirstEnergy had approximately $2.4 billion of short-term ~~indebtedness~~borrowings as of ~~September 30, 2008 compared to approximately $903 million as of~~March 31, 2009, and December 31, ~~2007.~~

~~As described above,~~2008. FirstEnergy, ~~and~~along with certain of its subsidiaries, ~~FES and FGCO entered into~~have access to $2.75 billion of short-term financing under a ~~new $300 million secured term loan~~revolving credit facility that expires in August 2012. A total of 25 banks participate in the facility, with Credit Suisse in October 2008. 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 a maturity of 30 days from the dateno one bank having more than 7.3% of the ~~borrowing. Once repaid, borrowings may not be re-borrowed.~~

total commitment. As of ~~September 30, 2008,~~May 1, 2009, FirstEnergy had $720 million of bank credit facilities in addition to the $2.75 billion revolving credit facility. Also, an aggregate of $550 million of accounts receivable financing facilities through the Ohio and Pennsylvania Companies ~~and Penn had the aggregate capability~~may be accessed to issue approximately $3.6 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $448 million, $457 million and $120 million, respectively, as of September 30, 2008. On June 19, 2008, FGCO established an FMB indenture. Based upon its net earnings and available bondable property additions as of September 30, 2008, FGCO had the capability to issue $3.1 billion of additional FMB under the terms of that indenture. Met-Ed and Penelec had the capability to issue secured debt of approximately $363 million and $310 million, respectively, under provisions of their senior note indentures as of September 30, 2008.

On September 22, 2008, FirstEnergy and the Utilities 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 Utilities may utilize the shelf registration statement to offer and sell unsecured, and in some cases, secured debt securities.

As discussed above, on October 20, 2008, OE issued and sold under the shelf registration statement $300 million of FMBs, comprised of $275 million 8.25% Series of 2008 due 2038 and $25 million 8.25% Series of 2008 due 2018. The net proceeds from this offering will be used to fundmeet working capital ~~expenditures~~requirements and for other general corporate purposes. ~~This issuance reduces OE’s capability to issue additional FMB under~~FirstEnergy’s available liquidity as of May 1, 2009, is summarized in the ~~terms of its mortgage indenture described above.~~following table:

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

As of September 30, 2008, FirstEnergy’s currently payable long-term debt includes approximately $2.1 billion (FES - $1.9 billion, OE - $156 million, 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.Revolving Credit Facility

Prior to September 2008, FirstEnergy had not experienced any unsuccessful remarketings of these variable-rate PCRBs. Coincident with recent disruptions in the variable-rate demand bond and capital markets generally, certain of the PCRBs have been tendered by bondholders to the trustee. As of October 31, 2008, $72.5 million of the PCRBs, all of which are backed by Wachovia Bank LOCs, had been tendered and not yet successfully remarketed. Of these, draws on the applicable LOCs were made for $72.4 million, all of which Wachovia honored. The reimbursement agreements between the subsidiary obligors and Wachovia require reimbursement of outstanding LOC draws by March 2009.

~~FirstEnergy and certain of its subsidiaries are party to a $2.75 billion revolving credit facility (included in the borrowing capability table above).~~ FirstEnergy has the capability to request an increase in the total commitments available under ~~this~~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 ~~September 30, 2008:~~

Revolving Regulatory and
Credit Facility Other Short-Term
Borrower

Sub-Limit

Debt Limitations

(In millions)
FirstEnergy $ 2,750 $ - (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)
FES 1,000 - (1)
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 guarantee~~

~~ATSI’s obligations of such borrower under the facility.~~

March 31, 2009:

2312

The revolving credit facility described above, combined with $720 million of additional credit facilities ($620 million available as of October 31, 2008) and an aggregate $550 million of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn ($445 million available as of October 31, 2008), are available to provide liquidity to meet working capital requirements and for other general corporate purposes for FirstEnergy and its subsidiaries.

	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 ~~September 30, 2008,~~March 31, 2009, FirstEnergy’s and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy(1)	~~59.6~~60.8	%
FES	57.3	%
OE	~~46.0~~44.8	%
Penn	~~19.2~~19.5	%
CEI	~~55.8~~54.4	%
TE	~~44.5~~44.6	%
JCP&L	~~31.0~~36.3	%
Met-Ed	~~43.7~~50.0	%
Penelec	~~50.1~~	%
~~FES~~	~~56.6~~52.0	%

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

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

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

credit facility.

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

FirstEnergy Money Pools

FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first ~~nine~~three months of ~~2008~~2009 was ~~3.13%~~0.97% for the regulated companies’ money pool and ~~3.09%~~1.01% for the unregulated companies’ money pool.

Pollution Control Revenue Bonds

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

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

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

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

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

Long-Term Debt Capacity

As of March 31, 2009, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.7 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. As a result of the issuance of senior secured notes by TE referred to below and related amendments to the TE mortgage indenture’s bonding ratio, that capacity decreased to $2.3 billion. The issuance of FMBs by the Ohio Companies is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $171 million, $164 million and $117 million, respectively, as of March 31, 2009. In April 2009, TE issued $300 million of new senior secured notes backed by FMBs. Concurrently with that issuance and in order to satisfy the limitation on secured debt under its senior note indenture, TE issued an additional $300 million of FMBs to secure $300 million of its outstanding unsecured senior notes originally issued in November 2006. Based upon FGCO’s FMB indenture, net earnings and available bondable property additions as of March 31, 2009, FGCO had the capability to issue $2.7 billion of additional FMBs under the terms of that indenture. Met-Ed and Penelec had the capability to issue secured debt of approximately $423 million and $321 million, respectively, under provisions of their senior note indentures as of March 31, 2009.

FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. On March 2, 2009, Moody’s assigned a Baa1 senior secured rating to FES-related secured issuances. The following table displays FirstEnergy’s, FES’ and the Utilities’ securities ratings as of ~~November 5, 2008. On August 1, 2008,~~April 30, 2009. S~~&P changed its outlook for FirstEnergy~~&P’s and ~~its subsidiaries from “negative” to “stable.” On November 5, 2008, S&P raised its senior unsecured rating on OE, Penn, CEI and TE to BBB from BBB-.~~ 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

~~Penn~~	~~Senior secured~~	A-	~~Baa1~~

JCP&L	Senior unsecured	BBB	Baa2

Met-Ed	Senior unsecured	BBB	Baa2

Penelec	Senior unsecured	BBB	Baa2

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

Changes in Cash Position

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

During the first quarter of 2009, FirstEnergy received $248 million of cash from dividends and equity repurchases from its subsidiaries and paid $168 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by FirstEnergy’s subsidiaries. In addition to paying dividends from retained earnings, each of FirstEnergy’s electric utility subsidiaries has authorization from the FERC to pay cash dividends from paid-in capital accounts, as long as the subsidiary’s debt to total capitalization ratio (without consideration of retained earnings) remains below 65%.

Cash Flows From Operating Activities

FirstEnergy's consolidated net cash from operating activities is provided primarily by its energy delivery services and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $462 million in the first three months of 2009 compared to $359 million in the first three months of 2008, as summarized in the following table:

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

2415

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

Cash Flows From Financing Activities

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

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

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

Short-term borrowings, net	$	-	$	746

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

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

Cash Flows From Investing Activities

Net cash flows used in investing activities resulted principally from property additions. Additions for the energy delivery services segment primarily include expenditures related to transmission and distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for the ~~nine~~three months ended ~~September 30,~~March 31, 2009, and 2008 ~~and 2007~~ by business segment:

Summary of Cash Flows Provided from Property
(Used for) Investing Activities Additions Investments Other Total
Sources (Uses) (In millions)
Nine Months Ended September 30, 2008
Energy delivery services

$
(621
)
$
33
$
(3 )
$
(591 )
Competitive energy services(1)

(1,430
)
(13 ) (121 ) (1,564 )
Other(2)

(106
)
57 (54 ) (103 )
Inter-Segment reconciling items

(20
)
(12 ) - (32 )
Total

$
(2,177
)
$
65
$
(178 )
$
(2,290 )

Nine Months Ended September 30, 2007

Energy delivery services

$
(609
)
$
6
$
(2 )
$
(605 )
Competitive energy services

(462
)
1,311 2 851
Other

(6
)
(4 ) 1 (9 )
Inter-Segment reconciling items

(50
)
(15 ) - (65 )
Total

$
(1,127
)
$
1,298
$
1
$
172

(1) Other investing activities include approximately $82 million in restricted funds to redeem outstanding debt in the fourth quarter of 2008.
(2) Other investing activities include approximately $64 million in cash investments for the equity interest in Signal Peak.

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

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

Three Months Ended March 31, 2008
Energy delivery services	$	(255	)	$	33		$	2		$	(220	)
Competitive energy services		(462	)		(3	)		(19	)		(484	)
Other		(12	)		68			-			56
Inter-segment reconciling items		18			(12	)		-			6
Total	$	(711	)	$	86		$	(17	)	$	(642	)

Net cash used for investing activities ~~was $2.3 billion~~ in the first ~~nine months~~quarter of ~~2008~~2009 increased by $36 million compared to ~~net~~the first quarter of 2008. The increase was primarily due to the absence in 2009 of cash ~~provided~~proceeds from ~~investing activities~~the sale of ~~$172 million~~telecommunication assets in the first nine months of 2007. The change was principally due to a $1.1 billion increase in property additions and the absence of $1.3 billion of proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction in the third quarter of ~~2007. The increased property additions reflected the acquisitions described above~~2008 and higher ~~planned air quality control~~cash investments for the Signal Peak mining operations in 2009, partially offset by lower property additions. Property additions decreased as a result of lower AQC system expenditures in the first ~~nine months~~quarter of 2009 and the absence in 2009 of acquisition costs for the Fremont Plant in the first quarter of 2008.

During the remaining three ~~months~~quarters of ~~2008,~~2009, capital requirements for property additions and capital leases are expected to be approximately ~~$555 million,~~$1.4 billion, including ~~$88~~approximately $225 million for nuclear fuel. ~~As of September 30, 2008,~~ FirstEnergy ~~had~~has additional requirements of approximately ~~$138~~$316 million for maturing long-term debt during the remainder of ~~2008,~~2009, of which ~~$125~~$100 million was redeemed in ~~October 2008.~~April 2009. These cash requirements are expected to be satisfied from a combination of internal cash, short-term credit arrangements and funds raised in the capital markets.

FirstEnergy's capital spending for the period ~~2008-2012~~2009-2013 is expected to be approximately ~~$7.6~~$8.1 billion (excluding nuclear ~~fuel, the purchase of nuclear sale and leaseback lessor equity interests, and the acquisition of Signal Peak)~~fuel), of which approximately ~~$2.1~~$1.6 billion applies to ~~2008.~~2009. Investments for additional nuclear fuel during the ~~2008-2012~~2009-2013 period are estimated to be approximately ~~$1.2~~$1.3 billion, of which about ~~$167~~$338 million applies to ~~2008.~~2009. During the same ~~periods,~~period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately ~~$892 million~~$1.0 billion and ~~$111~~$136 million, respectively, as the nuclear fuel is consumed.

While FirstEnergy believes its existing sources of liquidity will continue to be available to meet its anticipated obligations, management is reviewing its 2009 plans to determine what adjustments should be made to operating and capital budgets in response to the economic climate to reduce the need for external sources of capital. Management plans to reassess the economic value of discretionary projects; however, it expects to continue to meet commitments for required capital projects and necessary operational expenditures. Although this process is not yet complete, management expects that FirstEnergy's capital expenditures will be reduced from the levels previously anticipated.

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’s ~~or its subsidiaries’~~ credit ratings.

As of ~~September 30, 2008,~~March 31, 2009, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated ~~$4.2~~$4.5 billion, as summarized below:

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

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

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

Maximum
Guarantees and Other Assurances

Exposure

(In millions)
FirstEnergy Guarantees of Subsidiaries
Energy and Energy-Related Contracts (1)
$ 408
LOC (long-term debt) – interest coverage (2)
6
Other (3)
503
917

Subsidiaries’ Guarantees
Energy and Energy-Related Contracts 86
LOC (long-term debt) – interest coverage (2)
11
FES’ guarantee of FGCO’s sale and leaseback obligations 2,591
2,688

Surety Bonds 94
LOC (long-term debt) – interest coverage (2)
5
LOC (non-debt) (4)(5)
463
562
Total Guarantees and Other Assurances $ 4,167

(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~~

floating rate PCRBs with various maturities. The principal amount of floating-rate PCRBs of

~~$2.1~~ $1.6 billion is reflected asin currently payable long-term debt on FirstEnergy’s consolidated balance sheets.

(3)

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

nuclear decommissioning funding assurances.

Also includes $300 million for a Credit Suisse credit facility for FGCO that is guaranteed by both FirstEnergy and FES.

(4)

Includes ~~$38~~$145 million issued for various terms pursuant to LOC capacity available

under FirstEnergy’s revolving credit facility.

(5)

Includes approximately $291 million pledged in connection with the sale and

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

with the sale and leaseback of Perry Unit 1 by OE.

A $236 million LOC relating to the sale-leaseback of Beaver Valley Unit 2 by OE expires in May 2009 and is expected to be replaced by a $161 million LOC.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by its subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty's legal claim to be satisfied by ~~other~~ FirstEnergy assets. ~~The~~FirstEnergy believes the likelihood is remote that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade to below investment grade or a “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of ~~September 30, 2008, FirstEnergy's~~March 31, 2009, FirstEnergy’s maximum exposure under these collateral provisions was ~~$573~~$761 million as shown below:

Collateral Provisions
FES Utilities Total
(in millions)
Credit rating downgrade to
below investment grade

$
216

$
293

$
509

Material adverse event

56

8

64

Total

$
272

$
301

$
573

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

~~Additionally, stress~~Stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase the total potential amount to ~~$648~~$830 million, consisting of ~~$58~~$54 million due to “material adverse event” contractual clauses and ~~$590~~$776 million due to a below investment grade credit rating.

FES, through potential participation in utility sponsored competitive power procurement processes (including those of affiliates) or through forward hedging transactions and as a consequence of future power price movements, could be required to post significantly higher collateral to support its power transactions.

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

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

OFF-BALANCE SHEET ARRANGEMENTS

FES and the Ohio Companies have obligations that are not included on ~~FirstEnergy’s~~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 ~~decreased to $1.8~~is $1.7 billion as of ~~September 30, 2008, from $2.3 billion as of December~~March 31, ~~2007, due primarily to NGC’s purchase of certain lessor equity interests in Perry Unit 1 and Beaver Valley Unit 2 (see Note 9).~~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

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 ~~changes~~change in the fair value of commodity derivative contracts related to energy production during the ~~three months and nine months ended September 30, 2008 are~~first quarter of 2009 is summarized in the following table:

Three Months Nine Months
Increase (Decrease) in the Fair Value Ended September 30, 2008 Ended September 30, 2008
of 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 $ (616 ) $ (37 ) $ (653 ) $ (713 ) $ (26 ) $ (739 )
Additions/change in value of existing contracts 23 33 56 (10 ) 9 (1 )
Settled contracts 18 (6 )
12
148 7 155
Outstanding net liability at end of period (1)
(575 ) (10 ) (585 ) (575 ) (10 ) (585 )

Non-commodity Net Assets at End of Period:
Interest rate swaps (2)
- - - - - -
Net Liabilities - Derivative Contracts
at End of Period
$ (575 ) $ (10 ) $ (585 ) $ (575 ) $ (10 ) $ (585 )

Impact of Changes in Commodity Derivative Contracts(3)

Income Statement effects (pre-tax) $ (1 ) $ - $ (1 ) $ - $ - $ -
Balance Sheet effects:
Other comprehensive income (pre-tax) $ - $ 27 $ 27 $ - $ 16 $ 16
Regulatory assets (net) $ (42 ) $ - $ (42 ) $ (138 ) $ - $ (138 )

Fair Value of Commodity Derivative Contracts	Non-Hedge			Hedge			Total
	(In millions)
Change in the Fair Value of
Commodity Derivative Contracts:
Outstanding net liability as of January 1, 2009	$	(304	)	$	(41	)	$	(345	)
Additions/change in value of existing contracts		(227	)		(10	)		(237	)
Settled contracts		74			22			96
Outstanding net liability as of March 31, 2009 (1)	$	(457	)	$	(29	)	$	(486	)

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

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

(1) Includes $457 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset. (2) Interest rate swaps are treated as cash flow or fair value hedges. (3) Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

~~(1)~~

~~Includes $575 million in non-hedge commodity derivative contracts (primarily with NUGs) that are offset by a regulatory asset.~~

Derivatives are included on the Consolidated Balance Sheet as of March 31, 2009 as follows:

~~(2)~~

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

~~(3)~~

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

~~Derivatives are included on the Consolidated Balance Sheet as of September 30, 2008 as follows:~~

Balance Sheet Classification	Non-Hedge			Hedge			Total			Non-Hedge			Hedge			Total
	(In millions)									(In millions)
Current-
Other assets	$	-		$	14		$	14		$	1		$	23		$	24
Other liabilities		-			(26	)		(26	)		(1	)		(44	)		(45	)

Non-Current-
Other deferred charges		28			3			31			359			-			359
Other non-current liabilities		(603	)		(1	)		(604	)		(816	)		(12	)		(828	)

Net liabilities	$	(575	)	$	(10	)	$	(585	)	$	(457	)	$	(33	)	$	(490	)

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 5)4 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of ~~September 30, 2008~~March 31, 2009 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year

2008(1)

2009

2010

2011

2012

Thereafter

Total

(In millions)
Prices actively quoted(2)
$ (2) $ (5) $ (1) $ - $ - $ - $ (8)
Other external sources(3)
(58) (182) (151) (106) - - (497)
Prices based on models
-

-

-

-

(32)

(48)

(80)

Total(4)

$
(60)

$
(187)

$
(152)

$
(106)

$
(32)

$
(48)

$
(585)

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

(1) For the last ~~quarter~~three quarters of ~~2008.~~2009.

(2) Represents exchange traded NYMEX futures and options.

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

~~(4)~~ ~~Includes $575 million in non-hedge commodity derivative contracts (primarily with NUGs) that are offset by a regulatory asset.~~

(4)

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

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of ~~September 30, 2008.~~March 31, 2009. Based on derivative contracts held as of ~~September 30, 2008,~~March 31, 2009, an adverse 10% change in commodity prices would decrease net income by approximately $1 million during the next 12 months.

~~Interest Rate Swap Agreements - Fair Value Hedges~~

FirstEnergy historically utilized fixed-for-floating interest rate swap agreements as part of its effort to manage interest rate risk associated with its debt portfolio. In order to reduce counterparty exposure and lessen variable debt exposure under the current market conditions, FirstEnergy unwound its remaining interest rate swaps. During the first nine months of 2008, FirstEnergy received $3 million to terminate interest rate swaps with an aggregate notional value of $250 million. As of September 30, 2008, FirstEnergy had no outstanding interest rate swaps hedging the current debt portfolio.

Forward Starting Swap Agreements - Cash Flow Hedges

FirstEnergy utilizes forward starting swap agreements ~~(forward swaps)~~ in order to hedge a portion of the consolidated interest rate risk associated with anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in ~~2008~~2009 and ~~2009,~~2010, and anticipated variable-rate, short-term debt. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury and LIBOR rates between the date of hedge inception and the date of the debt issuance. FirstEnergy considers counterparty credit and nonperformance risk in its hedge assessments and continues to expect the forward-starting swaps to be effective in protecting against the risk of changes in future interest payments. During the first ~~nine~~three months of ~~2008,~~2009, FirstEnergy ~~entered into forward swaps with an aggregate notional value of $950 million and~~ terminated forward swaps with an aggregate notional value of ~~$750~~$100 million. FirstEnergy paid ~~$16~~$1.3 million in cash related to the terminations, $5$0.3 million of which was deemed ineffective and recognized in current period earnings. The remaining effective portion ($1.0 million) will be recognized over the terms of the associated future debt. As of ~~September 30, 2008,~~March 31, 2009, FirstEnergy had outstanding forward swaps with an aggregate notional amount of ~~$600~~$200 million and an aggregate fair value of ~~$(0.2)~~$(4) million.

	September 30, 2008						December 31, 2007							March 31, 2009							December 31, 2008
	Notional		Maturity		Fair		Notional		Maturity		Fair			Notional		Maturity		Fair			Notional		Maturity		Fair
Forward Starting Swaps	Amount		Date		Value		Amount		Date		Value			Amount		Date		Value			Amount		Date		Value
	(In millions)													(In millions)
Cash flow hedges	$	100		2009	$	-	$	-		2009	$	-		$	100		2009	$	(2	)		100		2009	$	(2	)
		100		2010		-		-		2010		-			100		2010		(2	)		100		2010		(2	)
		-		2015		-		25		2015		(1	)		-		2011		-			100		2011		1
		350		2018		-		325		2018		(1	)	$	200			$	(4	)		300			$	(3	)
		50		2020		-		50		2020		(1	)
	$	600			$	-	$	400			$	(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 ~~substantially all of its subsidiaries’~~certain employees. The ~~plans provide~~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 ~~of FirstEnergy~~ are remeasured annually using a December 31 measurement date. Reductions in plan assets from investment losses ~~will result~~during 2008 resulted in a decrease to the plans’ funded status of $1.7 billion and aan after-tax decrease into common stockholders’ equity ~~upon actuarial revaluation~~ of ~~the plan on January 1, 2009.~~

$1.2 billion. As of December 31, ~~2007, FirstEnergy’s~~2008, the pension plan was ~~overfunded,~~underfunded and ~~therefore,~~ FirstEnergy currently estimates that additional cash contributions will ~~not~~ be required ~~to make any contributions~~ in ~~2009~~2011 for the ~~2008~~2010 plan year. The overall actual investment ~~return as of October 31,~~result during 2008 was a loss of ~~25.4%~~23.8% compared to an assumed 9% positive return. Based on an 8%assumed 7% discount rate, ~~assumption, if the ultimate return for 2008 was to remain at a loss of 25.4%, 2009~~FirstEnergy’s pre-tax net periodic pension and OPEB expense ~~would be approximately $145~~was $43 million ~~an increase~~in the first quarter of approximately $180 million compared to the year 2008. If the ultimate return for 2008 were to remain at a loss of 25.4%, FirstEnergy would not be required to make contributions in 2010. However, if the assets were to decline an additional 1% from October 31, 2008 through the end of 2008, contributions of approximately $65 million would be required in 2010.2009.

This information does not consider any actions management may take to mitigate the impact of the asset return shortfalls, including changes in the amount and timing of future contributions. The actuarial assumptions used in the determination of pension and postretirement benefit costs are interrelated and changes in other assumptions could have the impact of offsetting all or a portion of the potential increase in benefit costs set forth above.

Nuclear decommissioning trust funds have been established to satisfy NGC’s and ~~the~~our Utilities’ nuclear decommissioning obligations. As of ~~September 30, 2008,~~March 31, 2009, approximately ~~47%~~31% of the funds were invested in equity securities and ~~53%~~69% 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 ~~$879~~$507 million as of ~~September 30, 2008.~~March 31, 2009. A hypothetical 10% decrease in prices quoted by stock exchanges would result in ~~an $88~~a $51 million reduction in fair value as of ~~September 30, 2008.~~March 31, 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. Nuclear decommissioning trust securities~~trusts based on the guidance for other-than-temporary impairments ~~totaled $63 million~~provided in SFAS 115, FSP SFAS 115-1 and SFAS 124-1. On March 27, 2009, FENOC submitted to the NRC a biennial evaluation of the funding status of these trusts and concluded that the amounts in the ~~first nine months~~trusts as of ~~2008.~~December 31, 2008, when coupled with the rates of return allowable by the NRC (over a safe store period for certain units) and the existing parental guarantee, would provide reasonable assurance of funding for decommissioning cost estimates under current NRC regulations. FirstEnergy does not expect to make additional cash contributions to the nuclear decommissioning trusts in 2009, other than the required annual TMI-2 trust contribution that is collected through customer rates. However, should the trust funds continue to experience declines in market value, FirstEnergy may be required to take measures, such as providing financial guarantees through ~~letters of credit~~LOCs or parental guarantees or making additional contributions to the trusts to ensure that the trusts are adequately funded and meet minimum NRC funding requirements.

CREDIT RISK

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

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB+ (S&P). As of ~~September 30, 2008,~~March 31, 2009, the largest credit concentration was with ~~JPMorgan Chase,~~JP Morgan, which is currently rated investment grade, representing ~~10.7%~~9.6% of FirstEnergy’s total approved credit risk. ~~Within FirstEnergy’s unregulated energy subsidiaries, 99% of existing credit, net of collateral and reserve, were with investment-grade counterparties as of September 30, 2008.~~

OUTLOOK

State Regulatory Matters

In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the 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 ~~certain costs~~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 ~~$128~~$130 million as of ~~September 30, 2008~~March 31, 2009 (JCP&L - ~~$64~~$54 million and Met-Ed - ~~$64~~$76 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed. The following table discloses regulatory assets by company:

September 30, December 31, Increase
Regulatory Assets* 2008 2007 (Decrease)
(In millions)
OE $ 621 $ 737 $ (116 )
CEI 796 871 (75 )
TE 145 204 (59 )
JCP&L 1,295 1,596 (301 )
Met-Ed 541 495 46
ATSI
35

42

(7
)
Total
$
3,433

$
3,945

$
(512
)

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

Penelec had net regulatory liabilities of approximately ~~$105~~$49 million

and ~~$74~~$137 million as

of ~~September 30, 2008~~March 31, 2009 and December 31, ~~2007,~~ 2008,

respectively. These net regulatory

liabilities are included in Other

Non-current Liabilities on the Consolidated Balance Sheets.

Regulatory assets by source are as follows:

September 30, December 31, Increase
Regulatory Assets By Source 2008 2007 (Decrease)
(In millions)
Regulatory transition costs $ 1,770 $ 2,363 $ (593 )
Customer shopping incentives 447 516 (69 )
Customer receivables for future income taxes 247 295 (48 )
Loss on reacquired debt 52 57 (5 )
Employee postretirement benefits 33 39 (6 )
Nuclear decommissioning, decontamination
and spent fuel disposal costs (81 ) (115 ) 34
Asset removal costs (207 ) (183 ) (24 )
MISO/PJM transmission costs 397 340 57
Fuel costs - RCP 213 220 (7 )
Distribution costs - RCP 450 321 129
Other
112

92

20

Total
$
3,433

$
3,945

$
(512
)

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

Reliability Initiatives

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

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

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

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

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

~~Ohio~~

~~On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider~~ and ~~to defer certain other increased fuel costs~~found it to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007 the Ohio Companies filed an applicationin full compliance with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the deferred fuel costs is addressed in the Ohio Companies’ comprehensive ESP filing, as described below. If the recovery of the deferred fuel costs is not resolved in the ESP, or in the event the MRO is implemented, recovery of the deferred fuel costs will be resolved in the proceeding that was instituted with the PUCO on February 8, 2008, as referenced above.

all audited reliability standards.

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

Ohio

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. ~~In its reports,~~On January 21, 2009, the PUCO ~~Staff recommended a~~granted the Ohio Companies’ application to increase electric distribution ~~rate increase in the range of $161~~rates by $136.6 million ~~to $180~~(OE - $68.9 million, ~~with $108~~CEI - $29.2 million ~~to $127 million~~and TE - $38.5 million). These increases went into effect for ~~distribution revenue increases~~OE and ~~$53 million for recovery of costs deferred under prior cases. Evidentiary hearings began~~TE on January ~~29, 2008~~23, 2009, and ~~continued through February 25, 2008. During~~will go into effect for CEI on May 1, 2009. Applications for rehearing of this order were filed by the ~~evidentiary hearings~~Ohio Companies and ~~filing of briefs, the PUCO Staff decreased their recommended revenue increase to a range of $117 million to $135 million. Additionally, in testimony submitted~~one other party on February ~~11, 2008, the~~20, 2009. The PUCO ~~Staff adopted a position regarding interest deferred~~granted these applications for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $58 million of interest costs deferred through September 30, 2008 ($0.12 per share of common stock). The Ohio Companies’ electric distribution rate request is addressed in their comprehensive ESP filing, as described below.rehearing on March 18, 2009.

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

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

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

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

MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO ~~outlines a CBP that would be implemented if~~application; however, the ~~ESP is not approved by~~PUCO later granted the ~~PUCO. Under SB221, a PUCO ruling on~~Ohio Companies’ application for rehearing for the ~~ESP filing is required within 150 days and an MRO decision is required within 90 days.~~purpose of further consideration of the matter. The ESP ~~proposes~~proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and ~~would~~ resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. ~~Major~~In response to the PUCO’s December 19, 2008 order, which significantly modified and approved the ESP as modified, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application in addition to continuing their current rate plan in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. The average winning bid price was equivalent to a retail rate of 6.98 cents per kwh. The power supply obtained through this process provides generation service to the Ohio Companies’ retail customers who choose not to shop with alternative suppliers. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider to recover increased costs resulting from the CBP but did not authorize OE and TE to continue collecting RTC or allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider allows for current recovery of the increased purchased power costs for OE and TE, and authorizes CEI to collect a portion of those costs currently and defer the remainder for future recovery.

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

a phase-in of new generation rates for up to a three-year period, whereby customers would receive a 10% phase-in credit; related costs (expected to approximate $429 million in 2009, $488 million in 2010 and $553 million in 2011) would be deferred for future collection over a period not to exceed 10 years;

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

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

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

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

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

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

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

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the continued recovery of transmission costs, including MISO, ancillary services and congestion charges, through an annually adjusted transmission rider; a separate rider will be established to recover costs incurred annually between May 1st ~~and September 30~~th for capacity purchases required to meet FERC, NERC, MISO and other applicable standards for planning reserve margin requirements in excess of amounts provided by FES as described in the ESP (the separate application for the recovery of these costs was filed on October 17, 2008);

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

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

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

~~Evidentiary hearings~~SB221 also requires electric distribution utilities to implement energy efficiency programs that achieve an energy savings equivalent of approximately 166,000 MWH in ~~the ESP case concluded on October 31, 2008~~2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and ~~no further hearings~~530,000 MWH in 2013. Utilities are ~~scheduled. The parties are~~also required to ~~submit initial briefs~~reduce peak demand in 2009 by ~~November 21, 2008,~~one percent, with ~~all reply briefs due by December 12, 2008.~~

The Ohio Companies’ MRO filing outlines a CBP for providing retail generation supply if the ESP is not approved by the PUCO or is changed and not accepted by the Ohio Companies. The CBP would use a “slice-of-system” approach where suppliers bid on tranches (approximately 100 MW)an additional seventy-five hundredths of ~~the Ohio Companies’ total customer load. If the Ohio Companies proceed~~one percent reduction each year thereafter through 2018. Costs associated with the MRO option, successful bidders (including affiliates) would be required to post independent credit requirements and could be subject to significant collateral calls depending upon power price movement. On September 16, 2008, the PUCO staff filed testimony and evidentiary hearings were held. The PUCO failed to act on October 29, 2008 as required under the statute. The Ohio Companiescompliance are ~~unable to predict the outcome of this proceeding.~~recoverable from customers.

The Ohio Companies included an interim pricing proposal as part of their ESP filing, if additional time is necessary for final PUCO approval of either the ESP or MRO. FES will be required to obtain FERC authorization to sell electric capacity or energy to the Ohio Companies under the ESP or MRO, unless a waiver is obtained (see FERC Matters).

Pennsylvania

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. ~~The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement.~~ If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. ~~Based on the PPUC’s January 11, 2007 order described below, if~~If FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.

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

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

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the Court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. The Commonwealth Court issued its decision on November 7, 2008, which affirmed the PPUC's January 11, 2007 order in all respects, including the deferral and recovery of transmission and congestion related costs.

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

On ~~February~~April 15, 2009, Met-Ed and Penelec filed revised TSCs with the PPUC for the period June 1, 2009 through May 31, 2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers, the ~~Governor of Pennsylvania proposed~~new TSC would result in an ~~EIS.~~approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The ~~EIS includes four pieces of proposed legislation that, according~~TSC for Met-Ed’s customers would increase to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the ~~Governor,~~higher rate, Met-Ed is ~~designed~~proposing to ~~reduce energy costs, promote energy independence and stimulate~~continue to recover the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that resultsprior period deferrals allowed in the ~~“lowest reasonable rate on~~PPUC’s May 2008 Order and defer $57.5 million of projected costs into a ~~long-term basis,”~~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 utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. As part of the 2008 state budget negotiations, the Alternative Energy Investment Act was enacted creating a $650 million alternative energy fund to increase the development and use of alternative and renewable energy, improve energy efficiency and reduce energy consumption. On October 8, 2008, House Bill 2200 as amended, was voted out of the full Senate and adopted by the House. period June 2009 through May 2010.

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

Major provisions of the legislation include:

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

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

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

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

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

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

~~The current legislative session ends on November 30, 2008, and any pending legislation~~Legislation addressing rate mitigation and the expiration of rate caps was not enacted ~~by that time must be re-introduced~~ in ~~order to be considered~~2008; however, several bills addressing these issues have been introduced in the ~~next~~current legislative session, which ~~begins~~began in January 2009. ~~While the~~The final form and impact of such legislation is ~~uncertain, several legislators and the Governor have indicated their intent to address these issues next year.~~uncertain.

On ~~September 25, 2008,~~February 26, 2009, the PPUC approved a Voluntary Prepayment Pan requested by Met-Ed and Penelec ~~filed for Commission approval of a Voluntary Prepayment Plan~~ that ~~would provide~~provides an opportunity for residential and small commercial customers to ~~pre-pay~~prepay an amount ~~which would earn interest at 7.5%,~~ on their monthly electric bills induring 2009 and ~~2010, to~~2010. Customer prepayments earn interest at 7.5% and will be used to reduce ~~electric rates~~electricity charges in 2011 and 2012.

On February 20, 2009, Met-Ed and Penelec ~~also intend to file~~filed with the PPUC a generation procurement plan ~~for~~covering the period January 1, 2011 through May 31, 2013. The companies’ plan is designed to provide adequate and ~~beyond with~~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 ~~PPUC later this year or early next year.~~use of a descending clock auction. Met-Ed and Penelec have requested ~~that~~PPUC approval of their plan by November 2009.

On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance Filing to the PPUC ~~approve~~in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the ~~Plan by mid-December 2008~~residential class with a corresponding increase in the generation rate and ~~are currently awaiting~~the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a ~~decision.~~corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $51 million), overall rates would remain unchanged. The PPUC must act on this filing within 120 days.

New Jersey

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, ~~and~~ costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of ~~September 30, 2008,~~March 31, 2009, the accumulated deferred cost balance totaled approximately ~~$210~~$165 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The ~~DRA~~DPA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. AFollowing public hearing ~~on these proposed rules was held on April 23, 2008~~ and consideration of comments from interested parties, ~~were submitted by May 19, 2008.~~the NJBPU approved final regulations effective April 6, 2009. These regulations are not expected to materially impact FirstEnergy or JCP&L.

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

~~On April 17, 2008, a draft EMP was released for public comment.~~

The ~~final~~ EMP was issued on October 22, 2008, ~~and establishes~~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.

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

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

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”)~~SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order ~~could be issued by~~is pending before the FERC, ~~by year-end 2008. In~~and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.

PJM Transmission Rate ~~Design~~

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

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, AEP appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit. Oral argument was held on April 13, 2009, and a decision is expected this summer.

The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce the costs of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge 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 ~~are due~~were filed on November 10, 2008. 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.

Post Transition Period Rate Design

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

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

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

MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. These markets would permit generators to sell, and load-serving entities to purchase, their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. Numerous parties filed requests for rehearing on March 26, 2008. On June 23, 2008, the FERC issued an order granting in part and denying in part rehearing.

On February 29, 2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor ASM and Consolidated Balancing Authority Initiative Verification plan and status and Real-Time Operations ASM Reversion plan. FERC action on this compliance filing remains pending. On March 26, 2008, MISO submitted a tariff filing in compliance with the FERC’s 30-day directives in the February 25 order. Numerous parties submitted comments and protests on April 16, 2008. The FERC issued an order accepting the revisions pending further compliance on June 23, 2008. On April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s 60-day directives in the February 25 order. FERC action on this compliance filing remains pending. On May 23, 2008, MISO submitted its amended Balancing Authority Agreement. On July 21, 2008, the FERC issued an order conditionally accepting the amended Balancing Authority Agreement and requiring a further compliance filing. On August 19, 2008, MISO submitted its compliance filing to the FERC. On July 25, 2008, MISO submitted another Readiness Certification. The FERC has not yet acted on this submission. MISO announced on August 26, 2008 that the startup of its market is postponed indefinitely. MISO commits to make a filing giving at least sixty days notice of the new effective date. The latest announced effective date for market startup is January 6, 2009.

~~Interconnection Agreement with AMP-Ohio~~

On May 29, 2008, TE filed with the FERC a proposed Notice of Cancellation effective midnight December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio protested this filing. TE also filed a Petition for Declaratory Order seeking a FERC ruling, in the alternative if cancellation is not accepted, of TE's right to file for an increase in rates effective January 1, 2009, for power provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a pleading agreeing that TE may seek an increase in rates, but arguing that any increase is limited to the cost of generation owned by TE affiliates. On August 18, 2008, the FERC issued an order that suspended the cancellation of the Agreement for five months, to become effective on June 1, 2009, and established expedited hearing procedures on issues raised in the filing and TE’s Petition for Declaratory Order. On October 14, 2008, the parties filed a settlement agreement and mutual notice of cancellation of the Interconnection Agreement effective midnight December 31, 2008. Upon acceptancewas denied by the FERC ~~this filing will terminate~~on December 19, 2008. On February 17, 2009, AEP appealed the ~~litigation~~FERC’s January 31, 2008, and December 19, 2008, orders to the ~~Interconnection Agreement, among other effects.~~

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.

Duquesne’s Request to Withdraw from PJM

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

FirstEnergy desires to continue to use its Duquesne zone generation resources to serve load in PJM. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification on whether Duquesne-zone generators could participate in PJM’s May 2008 auction for the 2011-2012 ~~planning year. In~~auction that excluded the ~~order,~~Duquesne load. The settlement agreement was filed on December 10, 2008 and approved by the FERC ~~ruled that although~~in an order issued on January 29, 2009. MISO opposed the ~~status~~settlement agreement pending resolution of exit fees alleged to be owed by Duquesne. The FERC did not resolve the exit fee issue in its order. On March 2, 2009, the PPUC filed for rehearing of the ~~Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators could contract with PJM for~~FERC's January 29, 2009 order approving the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with the FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction.

The FERC also directed MISO and PJM to resolve the substantive and procedural issues associated with Duquesne’s transition into MISO. As directed, PJM filed thirteen load-serving entity Capacity Payment Agreements and a Capacity Portability Agreement with the FERC. The Capacity Payment Agreements addressed Duquesne Zone load-serving entity obligations through May 31, 2011 with regards to RPM Capacity while the Capacity Portability Agreement addressed operational issues associated with the portability of such capacity. On September 30, 2008, the FERC approved both agreements, subject to conditions, taking notice of many operational and procedural issues brought forth bysettlement. Thereafter, FirstEnergy and other ~~market participants.~~parties filed in opposition to the rehearing request. The PPUC's rehearing request, and the pleadings in opposition thereto, are pending before the FERC.

Several issues surrounding Duquesne’s transition into MISO continue to be contested at the FERC. Specifically, Duquesne’s obligation to pay for transmission expansion costs allocated to the Duquesne zone when they were a member of PJM, and other issues in which market participants wish to be held harmless by Duquesne’s transition. FirstEnergy filed for rehearing on these issues on October 3, 2008. Duquesne’s transition into MISO is also contingent upon the start of MISO’s ancillary services market and consolidation of its balancing authorities, currently scheduled for January 6, 2009.

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

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by the FERC that established the RPM. In the complaint, the RPM Buyers request that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On July 11, 2008, PJM filed its answer to the complaint, in which it denied the allegation that the rates are unjust and unreasonable. Also on that date, FirstEnergy filed a motion to intervene.

On September 19, 2008, the FERC denied the RPM ~~Buyers~~Buyers’ complaint. However, the FERC did grant the RPM ~~Buyers~~Buyers’ request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on ~~its progress on contemplating~~potential adjustments to the RPM program as suggested ~~by the~~in a Brattle Group ~~in its report reviewing the RPM. The technical conference will take place in February, 2009.~~report. On ~~October 20,~~December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM ~~Buyers~~program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement talks. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.

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 ~~request~~compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; numerous parties have filed requests for rehearing of the ~~FERC’s~~March 26, 2009 Order. In addition, the FERC has indefinitely postponed the technical conference on RPM granted in the FERC order of September 19, ~~2008 order.~~

2008.

MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load-serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load-serving entities in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were ~~filed~~submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving 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 ~~purchase~~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 ~~these~~ orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process is ~~not~~ expected to ~~delay the~~start as planned effective June 1, 2009, ~~start date for~~the beginning of the MISO ~~Resource Adequacy.~~planning year.

~~Organized Wholesale Power Markets~~

The FERC issued a final rule on October 17, 2008, amending its regulations to “improve the operation of organized wholesale electric markets in the areas of: (1) demand response and market pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market-monitoring policies; and (4) the responsiveness of RTOs and ISOs to their customers and other stakeholders.” The RTOs and ISOs were directed to submit amendments to their respective tariffs to address these market operation improvements. The final rule directs RTOs to adopt market rules permitting prices to increase during periods of supply shortages and to permit enhanced participation by demand response resources. It also codifies and defines for the first time the roles and duties of independent market monitors within RTOs. Finally, it adopts requirements for enhanced access by stakeholders to RTO boards of directors. RTOs are directed to make compliance filings six months from the effective date of the final rule. The final rule is not expected to have any material effect on FirstEnergy's operations within MISO and PJM.

FES Sales to Affiliates

On October 24, 2008, FES, on its own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies inafter January 1, 2009 pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. ~~A ruling by~~On December 23, 2008, the FERC ~~is expected~~issued an order granting the ~~week~~waiver request and the Ohio Companies made the required compliance filing on December 30, 2008. In January 2009, several parties filed for rehearing of the FERC’s December ~~15,~~23, 2008 order. In response, FES filed an answer to requests for rehearing on February 5, 2009. The requests and responses are pending before the FERC.

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

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

Environmental Matters

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy estimates capital expenditures for environmental compliance of approximately ~~$1.4 billion~~$808 million for the period ~~2008-2012.~~

2009-2013.

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

Clean Air Act Compliance

FirstEnergy is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to ~~$32,500~~$37,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

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

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

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case ~~along with~~and seven other similar cases isare referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be ~~$1.3 billion~~$706 million for ~~2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650~~2009-2012 (with $414 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above. On September 8, 2008, the Environmental Enforcement Section of the DOJ sent a letter to OE regarding its view that the company was not in compliance with the Sammis NSR Litigation consent decree because the installation of an SNCR at Eastlake Unit 5 was not completed by December 31, 2006. However, the DOJ acknowledged that stipulated penalties could not apply under the terms of the Sammis NSR Litigation consent decree because Eastlake Unit 5 was idled on December 31, 2006 pending installation of the SNCR and advised that it had exercised its discretion not to seek any other penalties for this alleged non-compliance. OE disputed the DOJ's interpretation of the consent decree in a letter dated September 22, 2008. Although the Eastlake Unit 5 issue is no longer active, OE filed a dispute resolution petition on October 23, 2008, with the United States District Court for the Southern District of Ohio, due to potential impacts on its compliance decisions with respect to Burger Units 4 and 5. Under the Sammis NSR Litigation consent decree, an election to repower by December 31, 2012, install flue gas desulfurization (FGD) by December 31, 2010, or permanently shut down those units by December 31, 2010, is due no later than December 31, 2008. Although FirstEnergy will meet the December 31, 2008 deadline for making an election, one potential compliance option, should FGD be elected, would be to idle Burger Units 4 and 5 on December 31, 2010 pending completion of the FGD installation. Thus, OE is seeking a determination by the Court whether this approach is indeed in compliance with the terms of the Sammis NSR Litigation consent decree. The Court has scheduled a hearing on OE’s dispute resolution petition for November 17, 2008. The outcome of this dispute resolution process could have an impact on the option FirstEnergy ultimately elects with respect to Burger Units 4 and 5.

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

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints. The Pennsylvania Department of Health and the U.S. Agency for Toxic Substance and Disease Registry recently disclosed their intention to conduct additional air monitoring in the vicinity of the Mansfield plant.

On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and ~~1995~~2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. ~~By letter dated~~On October 1,30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. On December 5, 2008, New Jersey ~~informed the Court of its intent to file~~filed an amended ~~complaint.~~complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint on February 19, 2009. On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.

On June 11, 2008, the EPA issued a Notice and Finding of Violation to ~~MEW~~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. ~~MEW~~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 ~~MEW~~Mission Energy is disputed. Penelec is unable to predict the outcome of this matter.

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

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National Ambient Air Quality Standards

In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR ~~would have required~~requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” ~~The Court ruling also vacated the CAIR regional cap and trade requirements for SO~~2 ~~and NO~~X~~, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance.~~ 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 ~~October 21,~~December 23, 2008, the Court ~~ordered the parties who appealed~~reconsidered its prior ruling and allowed CAIR to ~~file responses~~remain in effect to “temporarily preserve its environmental values” until the ~~rehearing petitions by November 5,~~EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 ~~and directed them to address (1) whether any party is seeking vacatur of CAIR and (2) whether the Court should stay its vacatur of CAIR until EPA promulgates a revised rule.~~opinion. The future cost of compliance with these regulations may be substantial and will depend, in part, on ~~the Court’s ruling on rehearing, as well as~~ the action taken by the EPA ~~or Congress~~ in response to the Court’s ruling.

Mercury Emissions

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

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

Climate Change

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

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

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On ~~July 11, 2008,~~April 17, 2009, the EPA released ~~an Advance Notice~~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 ~~Proposed Rulemaking, soliciting input from~~several key greenhouse gases threaten the ~~public on~~health and welfare of future generations and that the ~~effects~~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 and~~change. Although the ~~potential ramifications~~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 ~~regulation of CO~~2 ~~under~~future emission requirements by the ~~CAA.~~EPA for stationary sources.

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

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April ~~14, 2008,~~1, 2009, the Supreme Court of the United States ~~granted a petition for a writ of certiorari to review~~reversed one significant aspect of the Second Circuit Court’s opinion ~~which is whether~~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. ~~Oral argument before the Supreme Court is scheduled for December 2, 2008.~~ FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies ~~the outcome of the Supreme Court’s review of the Second Circuit’s decision,~~and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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

Regulation of ~~Hazardous~~ Waste Disposal

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate non-hazardous waste. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. The future cost of compliance with coal combustion waste regulations may be substantial and will depend, in part, on the regulatory action taken by the EPA and implementation by the states.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of ~~September 30, 2008,~~March 31, 2009, FirstEnergy had approximately ~~$1.9~~$1.6 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any ~~rate of~~ return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.

The Utilities have been named as ~~PRPs~~potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all ~~PRPs~~potentially responsible parties for a particular site may be liable on a joint and several basis. ~~Therefore, environmental~~Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of ~~September 30, 2008,~~March 31, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately ~~$94~~$91 million ~~(JCP&L - $68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $24 million)~~ have been accrued through ~~September 30, 2008.~~March 31, 2009. Included in the total ~~for JCP&L~~ are accrued liabilities of approximately ~~$57~~$56 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

Other Legal Proceedings

Power Outages and Related Litigation

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

~~In August 2002,~~After various motions, rulings and appeals, the ~~trial Court granted partial summary judgment to JCP&L and dismissed the plaintiffs'~~Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, ~~and~~ strict product ~~liability. In November 2003,~~liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial ~~Court granted JCP&L's motion to decertify~~court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limitedonly to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation ~~resulting~~which resulted in planned and unplanned outages in the area during a 2-3 day ~~period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages~~period, and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which,(2) in March 2007, ~~reversed~~ the ~~decertification of the Red Bank class and~~Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. ~~JCP&L filed a petition for allowance of an appeal of~~Proceedings then continued at the ~~Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court~~trial court level and a case management conference with the presiding Judge was held on June 13, 2008. At that conference, counsel for the ~~plaintiffs~~Plaintiffs stated ~~their~~his intent to drop ~~their~~his efforts to create a class-wide damage model and, instead of dismissing the class action, expressed ~~their~~his desire for a bifurcated trial on liability and damages. The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario. Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure.In response, JCP&L ~~has received~~filed an objection to the plaintiffs’ proposed ~~plan of action, and intends to file its objection to the proposed~~trial plan and ~~also file a renewed~~another motion to decertify the class. On March 31, 2009, the trial court granted JCP~~&L is defending this action but is unable~~&L’s motion to ~~predict~~decertify the ~~outcome. No liability has been accrued as of September 30, 2008.~~class. On April 20, 2009, the Plaintiffs filed their appeal to the trial court's decision to decertify the class.

Nuclear Plant Matters

On May 14, 2007, the Office of Enforcement of the NRC issued a ~~DFI~~Demand for Information to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s ~~DFI~~Demand for Information reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the ~~DFI~~ response to the NRC on July 16, 2007. ~~On August 15, 2007, the~~The NRC issued a ~~confirmatory order~~Confirmatory Order imposing these ~~commitments.~~commitments on FENOC. In an April 23, 2009 Inspection Report, the NRC concluded that FENOC ~~must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC has conducted the employee training~~had completed all necessary actions required by the confirmatory order and a consultant has performed follow-up reviews to ensure the effectiveness of that training. The NRC continues to monitor FENOC’s compliance with all the commitments made in the confirmatory order.Confirmatory Order.

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

Other Legal Matters

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

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint, which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint and oral argument was held on November 5, 2008.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. ~~At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings.~~ On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. ~~On February 6, 2006, a federal district Court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005.~~ A final order identifying the individual damage amounts was issued on October 31, ~~2007. The~~2007 and the award appeal process was initiated. The union filed a motion with the federal Court 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. ~~The Court has yet~~On February 25, 2009, the federal district court denied JCP&L’s motion to ~~render its decision.~~vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009; the appeal process could take as long as 24 months. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.

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

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

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

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

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

In ~~December 2007,~~April 2009, the FASB issued ~~SFAS 141(R), which: (i) requires~~Staff Position FAS 157-4, which provides additional guidance to consider in estimating fair value when there has been a significant decrease in market activity for a financial asset. The FSP establishes a two-step process requiring a reporting entity to first determine if a market is not active in relation to normal market activity for the ~~acquiring~~asset. If evidence indicates the market is not active, an entity inwould then need to determine whether a ~~business combination to recognize all assets acquired and liabilities assumed~~quoted price in the ~~transaction; (ii) establishes~~market is associated with a distressed transaction. An entity will need to further analyze the ~~acquisition-date~~transactions or quoted prices, and an adjustment to the transactions or quoted prices may be necessary to estimate fair value. Additional disclosures related to the inputs and valuation techniques used in the fair value asmeasurements are also required. The FSP is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the ~~measurement objective~~FSP for ~~all assets acquired and liabilities assumed; and (iii) requires~~its interim period ending June 30, 2009. While the ~~acquirer~~FSP will expand disclosure requirements, FirstEnergy does not expect the FSP to ~~disclose to investors and other users all of the information they need to evaluate and understand the nature and~~have a material effect upon its financial effect of the business combination. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in deferred tax valuation allowances and income tax uncertainties made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. Under SFAS 141(R), adjustments to the acquired entity’s deferred tax assets and uncertain tax position balances occurring outside the measurement period will be recorded as a component of income tax expense, rather than goodwill. The impact of FirstEnergy’s application of this Standard in periods after implementation will be dependent upon acquisitions at that time.statements.

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

~~SFAS 160 - “Non-controlling Interests~~In April 2009, the FASB issued Staff Position FAS 115-2 and FAS 124-2, which changes the method to determine whether an other-than-temporary impairment exists for debt securities and the amount of impairment to be recorded in ~~Consolidated Financial Statements~~earnings. Under the FSP, management will be required to assert it does not have the intent to sell the debt security, and it is more likely than not it will not have to sell the debt security before recovery of its cost basis. If management is unable to make these assertions, the debt security will be deemed other-than-temporarily impaired and the security will be written down to fair value with the full charge recorded through earnings. If management is able to make the assertions, but there are credit losses associated with the debt security, the portion of impairment related to credit losses will be recognized in earnings while the remaining impairment will be recognized through other comprehensive income. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009 and does not expect the FSP to have a material effect upon its financial statements.

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

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

FSP FAS 132 (R)-1 – ~~an Amendment of ARB No. 51”~~“Employers’ Disclosures about Postretirement Benefit Plan Assets”

In December ~~2007,~~2008, the FASB issued ~~SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation~~Staff Position FAS 132(R)-1, which provides guidance on an employer’s disclosures about plan assets of a ~~subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.~~defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This ~~Statement~~FSP is effective for fiscal years ~~and interim periods within those fiscal years, beginning on or~~ending after December 15, ~~2008. Early adoption is prohibited. The Statement is not expected~~2009. FirstEnergy will expand its disclosures related to ~~have~~postretirement benefit plan assets as a ~~material impact on FirstEnergy’s financial statements.~~result of this FSP.

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

In March 2008, the FASB issued SFAS 161 that enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. The FASB believes that additional required disclosure of the fair values of derivative instruments and their gains and losses in a tabular format will provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. This Statement also requires cross-referencing within the footnotes to help users of financial statements locate important information about derivative instruments. The Statement is effective for reporting periods beginning after November 15, 2008. FirstEnergy expects this Standard to increase its disclosure requirements for derivative instruments and hedging activities.

4635

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of FirstEnergy Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of ~~September 30, 2008~~March 31, 2009 and the related consolidated statements of income, ~~and~~ comprehensive income and cash flows for each of the three-month ~~and nine-month~~ periods ended ~~September 30, 2008~~March 31, 2009 and ~~2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007.~~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, ~~2007,~~2008, and the related consolidated statements of income, ~~capitalization,~~ common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report dated February ~~28, 2008,~~24, 2009, we expressed an unqualified opinion on those consolidated financial statements. ~~In our opinion, the information set forth~~As discussed in Note 6 to the accompanying consolidated ~~balance sheet information as of~~financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, ~~2007, is fairly stated in all material respects in relation to the~~2008 consolidated balance sheet ~~from which it has been derived.~~

reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

~~November 6, 2008~~May 7, 2009

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FIRSTENERGY CORP.	FIRSTENERGY CORP.													FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME	CONSOLIDATED STATEMENTS OF INCOME													CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)	(Unaudited)													(Unaudited)

		Three Months						Nine Months						Three Months Ended
		Ended September 30						Ended September 30						March 31
		2008			2007			2008			2007
		(In millions, except per share amounts)												2009			2008
														(In millions, except
														per share amounts)
REVENUES:	REVENUES:
Electric utilities	Electric utilities	$	3,469		$	3,242		$	9,247		$	8,619		$	3,020		$	2,913
Unregulated businesses	Unregulated businesses		435			399			1,179			1,104			314			364
Total revenues *			3,904			3,641			10,426			9,723
Total revenues*															3,334			3,277

EXPENSES:	EXPENSES:
Fuel	Fuel		356			327			1,000			887			312			328
Purchased power	Purchased power		1,306			1,168			3,376			2,914			1,143			1,000
Other operating expenses	Other operating expenses		794			756			2,375			2,255			827			799
Provision for depreciation	Provision for depreciation		168			162			500			477			177			164
Amortization of regulatory assets	Amortization of regulatory assets		291			288			795			785			411			258
Deferral of new regulatory assets	Deferral of new regulatory assets		(58	)		(107	)		(261	)		(399	)		(93	)		(105	)
General taxes	General taxes		201			197			596			589			211			215
Total expenses	Total expenses		3,058			2,791			8,381			7,508			2,988			2,659

OPERATING INCOME	OPERATING INCOME		846			850			2,045			2,215			346			618

OTHER INCOME (EXPENSE):	OTHER INCOME (EXPENSE):
Investment income			40			30			73			93
Investment income (loss), net															(11	)		17
Interest expense	Interest expense		(192	)		(203	)		(559	)		(593	)		(194	)		(179	)
Capitalized interest	Capitalized interest		15			9			36			21			28			8
Total other expense	Total other expense		(137	)		(164	)		(450	)		(479	)		(177	)		(154	)

INCOME BEFORE INCOME TAXES	INCOME BEFORE INCOME TAXES		709			686			1,595			1,736			169			464

INCOME TAXES	INCOME TAXES		238			273			585			695			54			187

NET INCOME	NET INCOME	$	471		$	413		$	1,010		$	1,041			115			277

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

EARNINGS AVAILABLE TO PARENT														$	119		$	276


BASIC EARNINGS PER SHARE OF COMMON STOCK	BASIC EARNINGS PER SHARE OF COMMON STOCK	$	1.55		$	1.36		$	3.32		$	3.39		$	0.39		$	0.91

WEIGHTED AVERAGE NUMBER OF
BASIC SHARES OUTSTANDING			304			304			304			307

WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING															304			304

DILUTED EARNINGS PER SHARE OF COMMON STOCK	DILUTED EARNINGS PER SHARE OF COMMON STOCK	$	1.54		$	1.34		$	3.29		$	3.35		$	0.39		$	0.90

WEIGHTED AVERAGE NUMBER OF
DILUTED SHARES OUTSTANDING			307			307			307			311

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING															306			307

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	1.10		$	1.00		$	1.65		$	1.50		$	0.55		$	0.55


* Includes excise tax collections of $115 million and $113 million in the three months ended September 30, 2008 and 2007,
respectively, and $329 million and $322 million in the nine months ended September 2008 and 2007, respectively.
* Includes $109 million and $114 million of excise tax collections in the first quarter of 2009 and 2008, respectively.														* Includes $109 million and $114 million of excise tax collections in the first quarter of 2009 and 2008, respectively.

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

4837

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
(In millions)

NET INCOME $ 471 $ 413 $ 1,010 $ 1,041

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (20 ) (12 ) (60 ) (34 )
Unrealized gain (loss) on derivative hedges 26 (10 ) 21 10
Change in unrealized gain on available for sale securities (100 ) 26 (181 ) 89
Other comprehensive income (loss) (94 ) 4 (220 ) 65
Income tax expense (benefit) related to other
comprehensive income (34 ) - (81 ) 19
Other comprehensive income (loss), net of tax (60 ) 4 (139 ) 46

COMPREHENSIVE INCOME $ 411 $ 417 $ 871 $ 1,087

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

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In millions)

NET INCOME	$	115		$	277

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

COMPREHENSIVE INCOME		145			219

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		(4	)		1

COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT	$	149		$	218

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

4938

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2008 2007
(In millions)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents $ 181 $ 129
Receivables-
Customers (less accumulated provisions of $31 million and
$36 million, respectively, for uncollectible accounts) 1,383 1,256
Other (less accumulated provisions of $9 million and
$22 million, respectively, for uncollectible accounts) 148 165
Materials and supplies, at average cost 587 521
Prepayments and other 505 159
2,804 2,230
PROPERTY, PLANT AND EQUIPMENT:
In service 26,141 24,619
Less - Accumulated provision for depreciation 10,714 10,348
15,427 14,271
Construction work in progress 1,730 1,112
17,157 15,383
INVESTMENTS:
Nuclear plant decommissioning trusts 1,873 2,127
Investments in lease obligation bonds 674 717
Other 720 754
3,267 3,598
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 5,583 5,607
Regulatory assets 3,433 3,945
Pension assets 768 700
Other 550 605
10,334 10,857
$ 33,562 $ 32,068
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt $ 2,509 $ 2,014
Short-term borrowings 2,392 903
Accounts payable 744 777
Accrued taxes 253 408
Other 1,149 1,046
7,047 5,148
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 375,000,000 shares-
304,835,407 outstanding 31 31
Other paid-in capital 5,465 5,509
Accumulated other comprehensive loss (189 ) (50 )
Retained earnings 3,994 3,487
Total common stockholders' equity 9,301 8,977
Long-term debt and other long-term obligations 8,674 8,869
17,975 17,846
NONCURRENT LIABILITIES:
Accumulated deferred income taxes 2,793 2,671
Asset retirement obligations 1,314 1,267
Deferred gain on sale and leaseback transaction 1,035 1,060
Power purchase contract loss liability 603 750
Retirement benefits 914 894
Lease market valuation liability 319 663
Other 1,562 1,769
8,540 9,074
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 11)
$ 33,562 $ 32,068

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

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2009			2008
	(In millions)
ASSETS

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

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

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

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In millions)

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

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

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

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

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

5040

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months
Ended September 30
2008 2007
(In millions)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 1,010 $ 1,041
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 500 477
Amortization of regulatory assets 795 785
Deferral of new regulatory assets (261 ) (399 )
Nuclear fuel and lease amortization 82 75
Deferred purchased power and other costs (163 ) (265 )
Deferred income taxes and investment tax credits, net 278 (158 )
Investment impairment 63 16
Deferred rents and lease market valuation liability (62 ) (41 )
Accrued compensation and retirement benefits (127 ) (50 )
Stock-based compensation (74 ) (32 )
Commodity derivative transactions, net 4 5
Gain on asset sales (43 ) (35 )
Cash collateral 21 (50 )
Pension trust contribution - (300 )
Decrease (increase) in operating assets-
Receivables (117 ) (329 )
Materials and supplies (34 ) 62
Prepayments and other current assets (264 ) (39 )
Increase (decrease) in operating liabilities-
Accounts payable (34 ) (15 )
Accrued taxes (166 ) 355
Accrued interest 107 104
Electric service prepayment programs (58 ) (52 )
Other (29 ) 55
Net cash provided from operating activities 1,428 1,210

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 631 1,100
Short-term borrowings, net 1,489 -
Redemptions and Repayments-
Common stock - (918 )
Long-term debt (733 ) (647 )
Short-term borrowings, net - (535 )
Net controlled disbursement activity 6 6
Stock-based compensation tax benefit 24 16
Common stock dividend payments (503 ) (464 )
Net cash provided from (used for) financing activities 914 (1,442 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (2,177 ) (1,127 )
Proceeds from asset sales 64 37
Proceeds from sale and leaseback transaction - 1,329
Sales of investment securities held in trusts 1,144 1,010
Purchases of investment securities held in trusts (1,215 ) (1,126 )
Cash investments 72 48
Restricted funds for debt redemption (82 ) -
Other (96 ) 1
Net cash provided from (used for) investing activities (2,290 ) 172

Net change in cash and cash equivalents 52 (60 )
Cash and cash equivalents at beginning of period 129 90
Cash and cash equivalents at end of period $ 181 $ 30

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 ~~are~~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 ~~include~~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 ~~take into consideration~~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 ~~also has~~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 ~~2010. The fixed prices under~~2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty-day written notice prior to the ~~partial requirements agreement are expected to remain below wholesale market prices during the term~~end of the ~~agreement.~~calendar year. FES also supplies, through May 31, 2009, a portion of Penn’s default service requirements at market-based rates as a result of Penn’s 2008 competitive solicitations. FES’ ~~existing contractual obligations to Penn expire on May 31, 2009, but could continue if FES successfully bids in future competitive solicitations. FES’~~ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and ~~Michigan.~~Illinois. These sales may provide a greater portion of revenues in future years depending upon FES’ participation in its Ohio and Pennsylvania utility affiliates’ power procurement arrangements.

Results of Operations

In the first ~~nine~~three months of ~~2008,~~2009, net income ~~decreased~~increased to ~~$344~~$171 million from ~~$409~~$90 million in the same period in ~~2007.~~2008. The ~~decrease~~increase in net income was primarily due to higher revenues and lower fuel and purchased power costs, partially offset by higher other operating expenses, ~~partially offset by lower purchased power costs~~depreciation and ~~higher revenues.~~other miscellaneous expenses.

Revenues

Revenues increased by ~~$154~~$127 million in the first ~~nine~~three months of ~~2008~~2009 compared to the same period ~~of 2007~~in 2008 due to increases in revenues from non-affiliated and affiliated wholesale generation sales, partially offset by lower retail generation sales. The increase in revenues resulted from the following sources:

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

Retail generation sales revenues decreased due to reduced commercial and industrial contract renewals in the PJM market and the termination of certain government aggregation programs in the MISO market that were supplied by FES. Non-affiliated wholesale revenues increased ~~as a result of~~due to higher PJM capacity prices and ~~sales volumes in the PJM market, partially offset by decreased~~increased sales volumes in the MISO ~~market. Retail generation sales revenues decreased as a result of decreased sales in the PJM~~ market, partially offset by increased sales in the MISO market. Lower sales in the PJM market were primarily due to lower contract renewals for commercial and industrial customers. Increased sales in the MISO market were primarily due to FES capturing more shopping customers in Penn’s service territory, partially offset by lower customer usage.

~~The increase in affiliated company wholesale sales was due to higher unit prices for the Ohio Companies~~ partially offset by lower unit prices ~~for the Pennsylvania Companies~~ and ~~decreased sales~~ volumes ~~to all affiliates. Higher~~in PJM.

Increased affiliated company wholesale revenues resulted from higher unit prices onfor sales to the Ohio Companies, ~~resulted from~~under their CBP, partially offset by lower composite prices to the ~~PSA provision, whereby PSA rates reflect the increase~~Pennsylvania Companies and an overall decrease in ~~the Ohio Companies’ retail generation rates.~~affiliated sales volumes. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the overall composite price to decline. ~~The lower PSA sales volumes~~FES supplied less power to the Ohio ~~and Pennsylvania~~ Companies ~~were due to milder weather and decreased default service requirements~~ in ~~Penn’s service territory~~the first quarter of 2009 as ~~a result~~one of ~~its~~four winning bidders in the Ohio Companies’ RFP process.

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

Nine Months Ended
September 30, Increase
Revenues by Type of Service 2008 2007 (Decrease)
(In millions)
Non-Affiliated Generation Sales:

Retail

$
485

$
547

$
(62
)
Wholesale

509

426

83

Total Non-Affiliated Generation Sales

994

973

21

Affiliated Generation Sales

2,266

2,210

56

Transmission

113

71

42

Other

39

4

35

Total Revenues

$
3,412

$
3,258

$
154

5241

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated generation sales in the first ~~nine~~three months of ~~2008~~2009 compared to the same period last year:

Increase
Source of Change in Non-Affiliated Generation Revenues

(Decrease)

(In millions)
Retail:
Effect of 13.2% decrease in sales volumes
$ (73 )
Change in prices

11

(62
)
Wholesale:
Effect of 4.6% increase in sales volumes
19
Change in prices

64

83

Net Increase in Non-Affiliated Generation Revenues
$
21

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

Increase
Source of Change in Affiliated Generation Revenues

(Decrease)

(In millions)
Ohio Companies:
Effect of 1.7% decrease in sales volumes
$ (28 )
Change in prices

97

69

Pennsylvania Companies:
Effect of 0.2% decrease in sales volumes
(1 )
Change in prices

(12
)

(13
)
Net Increase in Affiliated Generation Revenues
$
56

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

Transmission revenue ~~increased $42~~decreased $8 million due ~~primarily~~ to decreased retail load in the MISO market ($14 million), partially offset by higher ~~rates for transmission service in MISO and PJM.~~PJM congestion revenues ($6 million). Other revenue increased ~~by $34~~$27 million ~~principally~~primarily due to NGC’s lease revenue received from ~~affiliated companies for the lessor~~its equity interests in the Beaver Valley Unit 2 and Perry ~~that were~~sale and leaseback transactions acquired ~~by NGC~~ during the second quarter of 2008.

Expenses

Total expenses ~~increased~~decreased by ~~$272~~$1 million in the first ~~nine~~three months of ~~2008~~2009 compared with the same period of ~~2007.~~2008. The following ~~tables summarize~~table summarizes the factors contributing to the changes in fuel and purchased power costs in the first ~~nine~~three months of ~~2008~~2009 from the same period last year:

~~Source of Change in Fuel Costs~~	~~Increase~~
	~~(In millions)~~
~~Fossil Fuel:~~
~~Change due to volume consumed~~	$	98
~~Change due to increased unit costs~~		73
		~~171~~
~~Nuclear Fuel:~~
~~Change due to volume consumed~~		4
~~Change due to increased unit costs~~		3
		7
~~Net Increase in Fuel Costs~~	$	~~178~~

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

Fossil fuel costs increased $171 million in the first nine months of 2008 as a result of the assignment of CEI’s and TE’s leasehold interest in the Bruce Mansfield Plant to FGCO in October 2007 and higher unit prices due to increased coal transportation costs, increased prices for existing eastern coal contracts and emission allowance costs. The increased fossil fuel costs were partially offset by a $25 million adjustment resulting from the annual coal inventory that reduced expense in the 2008 period. Nuclear fuel expense increased $7 million reflecting higher generation in 2008.

5342

Source of Change in Purchased Power Costs

Increase
(Decrease)

(In millions)
Purchased Power From Non-affiliates:
Change due to volume purchased
$ (121 )
Change due to increased unit costs
192
71
Purchased Power From Affiliates
Change due to volume purchased
(126 )
Change due to decreased unit costs
(8 )
(134 )
Net Decrease in Purchased Power Costs
$
(63
)

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

Purchased power costs decreased as a result of reduced purchases from affiliates, partially offset by increased non-affiliated purchased power costs. Purchases from affiliated companies decreased as a result of the assignment of CEI’s and TE’s leasehold interests in the Mansfield Plant to FGCO; prior to the assignment, FGCO purchased the associated output from CEI and TE. Purchased power costs from non-affiliates ~~increased~~decreased primarily as a result of lower market rates and reduced volume requirements. Purchases from affiliated companies increased as a result of higher ~~spot market prices~~unit costs on purchases from the Ohio Companies’ leasehold interests in ~~MISO~~Beaver Valley Unit 2 and ~~PJM partially offset by reduced volumes reflecting lower retail sales requirements and more available generation.~~Perry.

Other operating expenses increased by ~~$132~~$11 million in the first ~~nine~~three months of ~~2008~~2009 from the same period of ~~2007~~2008. The increase was primarily due to 2009 organizational restructuring costs ($4 million) and nuclear operating costs as a result of higher expenses associated with the 2009 Perry refueling outage than incurred with the 2008 Davis-Besse refueling outage ($11 million). Transmission expenses increased as a result of higher congestion charges ($7 million). Partially offsetting the increases were lower fossil contractor costs as a result of rescheduled maintenance activities ($7 million) and lower lease expenses relating to ~~the assignment of~~ CEI’s and TE’s leasehold ~~interests~~improvements in the Mansfield Plant that were transferred to FGCO ~~($36 million) and the sale and leaseback of Mansfield Unit 1 ($72 million) completed in the second half of 2007. Higher nuclear operating costs were due to an additional refueling outage~~ during the first ~~nine months~~quarter of 2008 ~~compared with 2007. Higher fossil operating costs were primarily due to a cancelled fossil project~~ ($135 million)~~, additional planned maintenance outages in 2008, employee benefits and reduced gains from excess emission allowance sales.~~.

Depreciation expense increased by ~~$26~~$12 million in the first ~~nine~~three months of ~~2008~~2009 primarily due to ~~the assignment of the Mansfield Plant to FGCO described above and~~ NGC’s acquisition of certain lessor equity ~~interest~~interests in the sale and leaseback of Perry and Beaver Valley Unit 2.2 ($7 million) and property additions since the first quarter of 2008.

Other Expense

Other expense ~~decreased~~increased by $8$14 million in the first ~~nine~~three months of ~~2008~~2009 from the same period of ~~2007~~2008 primarily due to a greater loss in value of nuclear decommissioning trust investments ($23 million) during the first quarter of 2009. Partially offsetting the higher securities impairments was a $10 million decline in interest expense as a result of ~~decreased~~higher capitalized interest ($3 million) and lower interest expense ~~(net of capitalized interest), partially offset by~~to affiliates due to lower ~~miscellaneous income. Affiliated interest expense decreased $36 million primarily as a result of reduced~~rates on loans from the unregulated money pool. Lower miscellaneous income resulted from a $13 million decrease in net earnings from nuclear decommissioning trust investments due primarily to securities impairments and reduced investment income from loans to the unregulated money poolmoneypool ($154 million).

Legal Proceedings

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

New Accounting Standards and Interpretations

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

5443

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of FirstEnergy Solutions Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its subsidiaries as of ~~September 30, 2008~~March 31, 2009 and the related consolidated statements of income, ~~and~~ comprehensive income and cash flows for each of the three-month ~~and nine-month~~ periods ended ~~September 30, 2008~~March 31, 2009 and ~~2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007.~~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, ~~2007,~~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 ~~28, 2008,~~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, ~~2007,~~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

~~November 6, 2008~~May 7, 2009

5544

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
(In thousands)

REVENUES:
Electric sales to affiliates $ 785,681 $ 805,372 $ 2,266,271 $ 2,209,743
Electric sales to non-affiliates 381,483 337,561 994,100 972,591
Other 74,440 27,975 151,627 75,598
Total revenues 1,241,604 1,170,908 3,411,998 3,257,932

EXPENSES:
Fuel 349,946 301,786 982,185 804,201
Purchased power from non-affiliates 221,493 228,755 648,556 577,831
Purchased power from affiliates 15,821 62,508 75,834 209,576
Other operating expenses 279,184 235,033 863,468 731,774
Provision for depreciation 64,633 48,500 170,535 145,030
General taxes 21,736 22,242 64,728 64,870
Total expenses 952,813 898,824 2,805,306 2,533,282

OPERATING INCOME 288,791 272,084 606,692 724,650

OTHER INCOME (EXPENSE):
Miscellaneous income 18,427 12,655 13,449 47,756
Interest expense - affiliates (8,015 ) (9,641 ) (25,953 ) (61,904 )
Interest expense - other (32,769 ) (31,794 ) (81,809 ) (70,845 )
Capitalized interest 12,395 5,131 29,599 12,763
Total other expense (9,962 ) (23,649 ) (64,714 ) (72,230 )

INCOME BEFORE INCOME TAXES 278,829 248,435 541,978 652,420

INCOME TAXES 93,174 93,671 198,245 243,736

NET INCOME 185,655 154,764 343,733 408,684

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (1,821 ) (1,360 ) (5,462 ) (4,080 )
Unrealized gain on derivative hedges 27,277 4,863 15,075 9,451
Change in unrealized gain on available-for-sale securities (90,198 ) 21,263 (159,759 ) 80,053
Other comprehensive income (loss) (64,742 ) 24,766 (150,146 ) 85,424
Income tax expense (benefit) related to other
comprehensive income (24,781 ) 8,915 (55,497 ) 30,474
Other comprehensive income (loss), net of tax (39,961 ) 15,851 (94,649 ) 54,950

TOTAL COMPREHENSIVE INCOME $ 145,694 $ 170,615 $ 249,084 $ 463,634

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

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)


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

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

OPERATING INCOME		304,294			175,733

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

INCOME BEFORE INCOME TAXES		262,503			147,747

INCOME TAXES		91,822			57,763

NET INCOME		170,681			89,984

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

TOTAL COMPREHENSIVE INCOME	$	178,079		$	59,433

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

5645

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2008 2007
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2 $ 2
Receivables-
Customers (less accumulated provisions of $5,840,000 and $8,072,000,
respectively, for uncollectible accounts) 137,126 133,846
Associated companies 263,779 376,499
Other (less accumulated provisions of $6,798,000 and $9,000
respectively, for uncollectible accounts) 22,924 3,823
Notes receivable from associated companies 156,926 92,784
Materials and supplies, at average cost 497,276 427,015
Prepayments and other 179,530 92,340
1,257,563 1,126,309
PROPERTY, PLANT AND EQUIPMENT:
In service 9,834,662 8,294,768
Less - Accumulated provision for depreciation 4,211,717 3,892,013
5,622,945 4,402,755
Construction work in progress 1,385,652 761,701
7,008,597 5,164,456
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts 1,145,384 1,332,913
Long-term notes receivable from associated companies 62,900 62,900
Other 40,573 40,004
1,248,857 1,435,817
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits 230,341 276,923
Lease assignment receivable from associated companies 71,356 215,258
Goodwill 24,248 24,248
Property taxes 47,774 47,774
Pension assets 14,764 16,723
Unamortized sale and leaseback costs 57,365 70,803
Other 49,702 43,953
495,550 695,682
$ 10,010,567 $ 8,422,264
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 1,938,215 $ 1,441,196
Short-term borrowings-
Associated companies 311,750 264,064
Other 1,000,000 300,000
Accounts payable- ��
Associated companies 361,447 445,264
Other 163,173 177,121
Accrued taxes 80,719 171,451
Other 217,914 237,806
4,073,218 3,036,902
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 750 shares-
7 shares outstanding 1,461,541 1,164,922
Accumulated other comprehensive income 46,005 140,654
Retained earnings 1,409,388 1,108,655
Total common stockholder's equity 2,916,934 2,414,231
Long-term debt and other long-term obligations 558,923 533,712
3,475,857 2,947,943
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction 1,035,013 1,060,119
Accumulated deferred investment tax credits 63,968 61,116
Asset retirement obligations 849,475 810,114
Retirement benefits 67,567 63,136
Property taxes 48,095 48,095
Lease market valuation liability 319,129 353,210
Other 78,245 41,629
2,461,492 2,437,419
COMMITMENTS AND CONTINGENCIES (Note 11)
$ 10,010,567 $ 8,422,264

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

FIRSTENERGY SOLUTIONS CORP.

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

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

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

5746

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months
Ended September 30
2008 2007
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 343,733 $ 408,684
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 170,535 145,030
Nuclear fuel and lease amortization 81,950 75,102
Deferred rents and lease market valuation liability (36,702 ) -
Deferred income taxes and investment tax credits, net 91,082 (381,042 )
Investment impairment 58,173 14,296
Accrued compensation and retirement benefits (2,110 ) 3,414
Commodity derivative transactions, net 3,634 4,913
Gain on asset sales (11,319 ) (12,105 )
Cash collateral, net (8,827 ) (19,798 )
Pension trust contribution - (64,020 )
Decrease (increase) in operating assets:
Receivables 106,574 (30,172 )
Materials and supplies (35,498 ) 48,123
Prepayments and other current assets (10,762 ) (5,118 )
Increase (decrease) in operating liabilities:
Accounts payable (61,035 ) (108,949 )
Accrued taxes (90,767 ) 434,568
Accrued interest 15,420 14,355
Other (59,948 ) (5,254 )
Net cash provided from operating activities 554,133 522,027

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 537,375 -
Equity contribution from parent 280,000 700,000
Short-term borrowings, net 747,686 -
Redemptions and Repayments-
Common stock - (600,000 )
Long-term debt (460,902 ) (1,110,174 )
Short-term borrowings, net - (785,127 )
Common stock dividend payments (43,000 ) (67,000 )
Net cash provided from (used for) financing activities 1,061,159 (1,862,301 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (1,417,205 ) (482,907 )
Proceeds from asset sales 15,218 12,990
Proceeds from sale and leaseback transaction - 1,328,919
Sales of investment securities held in trusts 596,291 521,535
Purchases of investment securities held in trusts (624,899 ) (552,779 )
Loan repayments from (loans to) associated companies, net (64,142 ) 510,307
Restricted funds for debt redemption (81,640 ) -
Other (38,915 ) 2,209
Net cash provided from (used for) investing activities (1,615,292 ) 1,340,274

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

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

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)

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

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

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

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

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

5847

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. ~~OE’s~~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 ~~requirements are provided by FES – an affiliated company. Penn purchases power from FES~~procurement issues for 2009 and ~~third-party suppliers through a competitive RFP process.~~beyond.

Results of Operations

In the first ~~nine~~three months of ~~2008,~~2009, net income ~~increased~~decreased to ~~$165~~$12 million from ~~$148~~$44 million in the same period of ~~2007.~~2008. The ~~increase~~decrease primarily resulted from ~~higher electric sales revenues~~the completion of the recovery of transition costs at the end of 2008 and ~~lower purchased power costs, partially offset~~accrued obligations principally associated with the implementation of the ESP in 2009. OE’s financial statements include certain immaterial adjustments that relate to prior periods that reduced net income by ~~a decrease in~~$3 million for the ~~deferral~~first quarter of ~~new regulatory assets and lower investment income.~~2009.

Revenues

Revenues increased by ~~$73~~$96 million, or ~~3.9%~~14.8%, in the first ~~nine~~three months of ~~2008~~2009 compared with the same period in ~~2007,~~2008, primarily due to increases in retail generation revenues ($51114 million) and wholesale revenues ($35 million), partially offset by decreases in distribution throughput revenues ($1653 million).

Retail generation revenues increased primarily due to higher average prices across all customer classes ~~partially offset by decreased~~and increased KWH sales to residential and commercial customers, reflecting a decrease in ~~all sectors. The higher average prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see Regulatory Matters). Milder weather~~customer shopping for those sectors as most of OE’s franchise customers returned to PLR service in ~~the first nine months of 2008 primarily caused the lower~~December 2008. Reduced industrial KWH sales ~~(cooling degree days decreased~~reflected weakened economic conditions in OE’s and Penn’s service ~~territories by 23.3% and 21.5%, respectively,~~territories. Additional generation revenues from OE’s fuel rider effective in January 2009 contributed to the ~~same period in 2007)~~rate variances (see Regulatory Matters – Ohio). ~~Commercial and industrial retail KWH sales were also impacted by increased customer shopping in Penn’s service territory in the first nine months of 2008.~~

Changes in retail generation sales and revenues in the first ~~nine~~three months of ~~2008~~2009 from the same period in ~~2007~~2008 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)

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

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

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

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

Distribution KWH Deliveries	Decrease

Residential		~~(2.3)~~(1.0	)%
Commercial		~~(2.1)~~(4.7	)%
Industrial		~~(4.4)~~ (22.9	%
~~Decrease in Generation Sales~~		~~(2.9)~~	%

Retail Generation Revenues Increase
(In millions)
Residential $ 23
Commercial 11
Industrial 17
Increase in Generation Revenues $ 51

Revenues from distribution throughput increased by $16 million in the first nine months of 2008 compared to the same period in 2007 due to higher average unit prices for all customer classes, partially offset by lower KWH deliveries in all sectors. The higher average prices resulted from Ohio transmission rider increases that became effective July 1, 2007 and July 1, 2008. The lower KWH deliveries to residential and commercial customers reflected the milder weather conditions described above.

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

~~Distribution KWH Deliveries~~	~~Decrease~~

~~Residential~~	~~(1.8)~~	%
~~Commercial~~	~~(0.8)~~	%
~~Industrial~~	~~(2.2)~~	)%
Decrease in Distribution Deliveries	~~(1.7)~~(9.2	)%

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

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

Expenses

Total expenses increased by ~~$38~~$143 million in the first ~~nine~~three months of ~~2008~~2009 from the same period of ~~2007.~~2008. The following table presents changes from the prior year by expense category.

Expenses – Changes Increase (Decrease)
(In millions)
Purchased power costs $ (40 )
Other operating costs (1 )
Provision for depreciation 1
Amortization of regulatory assets 9
Deferral of new regulatory assets 66
General taxes 3
Net Increase in Expenses $ 38

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

~~Lower~~Higher purchased power costs inare primarily due to the results of the CBP used for the procurement of electric generation for retail customers during the first ~~nine months~~quarter of ~~2008 primarily reflected the lower~~2009 and higher volumes due to increased retail generation KWH ~~sales, reducing the purchase volumes required. Higher amortization of regulatory assets~~sales. The increase in other operating costs for the first ~~nine~~three months of ~~2008~~2009 was primarily due to ~~increased~~accruals for economic development programs, in accordance with the PUCO-approved ESP, and energy efficiency obligations. Lower amortization of ~~MISO transmission cost deferrals. The decrease in the deferral of new~~net regulatory assets ~~for the first nine months of 2008~~ was primarily due to the conclusion of transition cost amortization in 2008, partially offset by lower MISO transmission cost deferrals ~~($26 million)~~ and lower RCP ~~fuel deferrals ($36 million), as more transmission and generation costs were recovered from customers through PUCO-approved riders. The increase~~distribution deferrals.

Other Expenses

Other expenses increased by $8 million in ~~general taxes for~~ the first ~~nine~~three months of 2009 compared to the same period in 2008 ~~was~~ primarily due to higher ~~property taxes.~~

~~Other Income~~

~~Other income decreased $20 million in the first nine months of 2008 as compared~~interest expense associated with the ~~same period~~issuance of ~~2007 primarily due to reductions~~OE’s $300 million of FMBs in ~~interest income on notes receivable from associated companies resulting from principal payments since the third quarter of 2007.~~October 2008.

Legal Proceedings

New Accounting Standards and Interpretations

6049

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Ohio Edison Company:

We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of ~~September 30, 2008~~March 31, 2009 and the related consolidated statements of income, ~~and~~ comprehensive income and cash flows for each of the three-month ~~and nine-month~~ periods ended ~~September 30, 2008~~March 31, 2009 and ~~2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007.~~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, ~~2007,~~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 ~~28, 2008,~~24, 2009, we expressed an unqualified opinion on those consolidated financial statements. ~~In our opinion, the information set forth~~As discussed in Note 6 to the accompanying consolidated ~~balance sheet information as of~~financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, ~~2007, is fairly stated in all material respects in relation to the~~2008 consolidated balance sheet ~~from which it has been derived.~~

reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

~~November 6, 2008~~May 7, 2009

6150

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
(In thousands)

REVENUES:
Electric sales $ 671,761 $ 638,336 $ 1,877,300 $ 1,802,110
Excise tax collections 30,500 30,472 87,165 89,077
Total revenues 702,261 668,808 1,964,465 1,891,187

EXPENSES:
Purchased power 349,374 364,709 997,609 1,037,200
Other operating costs 146,048 144,869 423,993 424,970
Provision for depreciation 14,997 19,482 57,904 57,440
Amortization of regulatory assets 57,660 53,026 154,054 144,569
Deferral of new regulatory assets (15,078 ) (41,417 ) (66,390 ) (132,410 )
General taxes 49,255 46,158 144,097 141,296
Total expenses 602,256 586,827 1,711,267 1,673,065

OPERATING INCOME 100,005 81,981 253,198 218,122

OTHER INCOME (EXPENSE):
Investment income 19,323 19,827 45,866 67,803
Miscellaneous income (expense) (1,089 ) 670 (5,180 ) 3,362
Interest expense (17,309 ) (20,311 ) (51,851 ) (62,749 )
Capitalized interest 55 136 324 398
Total other income (expense) 980 322 (10,841 ) 8,814

INCOME BEFORE INCOME TAXES 100,985 82,303 242,357 226,936

INCOME TAXES 28,501 34,089 77,122 79,074

NET INCOME 72,484 48,214 165,235 147,862

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirment benefits (3,994 ) (3,423 ) (11,982 ) (10,270 )
Change in unrealized gain on available-for-sale securities (9,936 ) 2,442 (20,310 ) 7,415
Other comprehensive loss (13,930 ) (981 ) (32,292 ) (2,855 )
Income tax benefit related to other comprehensive loss (5,105 ) (573 ) (11,931 ) (1,688 )
Other comprehensive loss, net of tax (8,825 ) (408 ) (20,361 ) (1,167 )

TOTAL COMPREHENSIVE INCOME $ 63,659 $ 47,806 $ 144,874 $ 146,695

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 STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

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

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

OPERATING INCOME		30,168			77,064

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

INCOME BEFORE INCOME TAXES		15,653			70,936

INCOME TAXES		4,005			26,873

NET INCOME		11,648			44,063

Less: Noncontrolling interest income		146			154

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

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	11,648		$	44,063

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

COMPREHENSIVE INCOME		14,148			36,760

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		146			154

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

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

6251

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2008 2007
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 715 $ 732
Receivables-
Customers (less accumulated provisions of $6,888,000 and 8,032,000,
respectively, for uncollectible accounts) 268,252 248,990
Associated companies 205,776 185,437
Other (less accumulated provisions of $13,000 and $5,639,000
respectively, for uncollectible accounts) 16,731 12,395
Notes receivable from associated companies 362,695 595,859
Prepayments and other 11,285 10,341
865,454 1,053,754
UTILITY PLANT:
In service 2,854,174 2,769,880
Less - Accumulated provision for depreciation 1,101,572 1,090,862
1,752,602 1,679,018
Construction work in progress 41,880 50,061
1,794,482 1,729,079
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies 257,457 258,870
Investment in lease obligation bonds 248,751 253,894
Nuclear plant decommissioning trusts 115,523 127,252
Other 31,441 36,037
653,172 676,053
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets 621,192 737,326
Pension assets 250,762 228,518
Property taxes 65,520 65,520
Unamortized sale and leaseback costs 41,381 45,133
Other 33,820 48,075
1,012,675 1,124,572
$ 4,325,783 $ 4,583,458
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 159,662 $ 333,224
Short-term borrowings-
Associated companies - 50,692
Other 242,449 2,609
Accounts payable-
Associated companies 95,604 174,088
Other 20,902 19,881
Accrued taxes 58,800 89,571
Accrued interest 14,216 22,378
Other 123,177 65,163
714,810 757,606
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 shares outstanding 1,224,039 1,220,512
Accumulated other comprehensive income 28,025 48,386
Retained earnings 207,512 307,277
Total common stockholder's equity 1,459,576 1,576,175
Long-term debt and other long-term obligations 841,871 840,591
2,301,447 2,416,766
NONCURRENT LIABILITIES:
Accumulated deferred income taxes 776,042 781,012
Accumulated deferred investment tax credits 14,040 16,964
Asset retirement obligations 79,372 93,571
Retirement benefits 173,297 178,343
Deferred revenues - electric service programs 14,954 46,849
Other 251,821 292,347
1,309,526 1,409,086
COMMITMENTS AND CONTINGENCIES (Note 11)
$ 4,325,783 $ 4,583,458

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

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	311,192		$	146,343
Receivables-
Customers (less accumulated provisions of $6,621,000 and $6,065,000, respectively,
for uncollectible accounts)		292,159			277,377
Associated companies		217,455			234,960
Other (less accumulated provisions of $8,000 and $7,000, respectively,
for uncollectible accounts)		19,492			14,492
Notes receivable from associated companies		77,264			222,861
Prepayments and other		22,544			5,452
		940,106			901,485
UTILITY PLANT:
In service		2,915,643			2,903,290
Less - Accumulated provision for depreciation		1,120,219			1,113,357
		1,795,424			1,789,933
Construction work in progress		47,022			37,766
		1,842,446			1,827,699
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		256,473			256,974
Investment in lease obligation bonds		239,501			239,625
Nuclear plant decommissioning trusts		112,778			116,682
Other		98,729			100,792
		707,481			714,073
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		544,782			575,076
Property taxes		60,542			60,542
Unamortized sale and leaseback costs		38,880			40,130
Other		32,418			33,710
		676,622			709,458
	$	4,166,655		$	4,152,715
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	2,697		$	101,354
Short-term borrowings-
Associated companies		79,810			-
Other		1,540			1,540
Accounts payable-
Associated companies		115,778			131,725
Other		54,237			26,410
Accrued taxes		72,736			77,592
Accrued interest		23,717			25,673
Other		124,871			85,209
		475,386			449,503
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 shares outstanding		1,224,347			1,224,416
Accumulated other comprehensive loss		(181,885	)		(184,385	)
Retained earnings		265,525			254,023
Total common stockholder's equity		1,307,987			1,294,054
Noncontrolling interest		7,252			7,106
Total equity		1,315,239			1,301,160
Long-term debt and other long-term obligations		1,123,966			1,122,247
		2,439,205			2,423,407
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		650,601			653,475
Accumulated deferred investment tax credits		12,700			13,065
Asset retirement obligations		81,944			80,647
Retirement benefits		305,943			308,450
Other		200,876			224,168
		1,252,064			1,279,805
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	4,166,655		$	4,152,715

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

6352

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months
Ended September 30
2008 2007
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 165,235 $ 147,862
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 57,904 57,440
Amortization of regulatory assets 154,054 144,569
Deferral of new regulatory assets (66,390 ) (132,410 )
Amortization of lease costs 28,535 28,567
Deferred income taxes and investment tax credits, net 17,267 (29,155 )
Accrued compensation and retirement benefits (41,190 ) (34,572 )
Pension trust contribution - (20,261 )
Decrease (increase) in operating assets-
Receivables (26,009 ) (70,098 )
Prepayments and other current assets 2,065 (3,542 )
Increase (decrease) in operating liabilities-
Accounts payable (77,463 ) 89,550
Accrued taxes (27,776 ) (25,734 )
Accrued interest (8,162 ) (7,277 )
Electric service prepayment programs (31,895 ) (27,455 )
Other (1,283 ) 9,868
Net cash provided from operating activities 144,892 127,352

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net 189,148 -
Redemptions and Repayments-
Common stock - (500,000 )
Long-term debt (175,588 ) (1,190 )
Short-term borrowings, net - (64,475 )
Dividend Payments-
Common stock (265,000 ) (150,000 )
Net cash used for financing activities (251,440 ) (715,665 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (135,450 ) (109,461 )
Sales of investment securities held in trusts 115,988 31,624
Purchases of investment securities held in trusts (121,871 ) (36,194 )
Loan repayments from associated companies, net 234,577 685,364
Cash investments 5,143 17,316
Other 8,144 (321 )
Net cash provided from investing activities 106,531 588,328

Net increase (decrease) in cash and cash equivalents (17 ) 15
Cash and cash equivalents at beginning of period 732 712
Cash and cash equivalents at end of period $ 715 $ 727

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 STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	In thousands)

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

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

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

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

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

6453

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. ~~CEI’s~~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 ~~requirements are primarily provided by FES – an affiliated company.~~procurement issues for 2009 and beyond.

Results of Operations

~~Net income~~CEI recognized a net loss of $105 million in the first ~~nine~~three months of ~~2008 increased~~2009 compared to ~~$218 million from $211~~net income of $58 million in the same period of ~~2007.~~2008. The ~~increase~~decrease resulted primarily from ~~the elimination of fuel costs and lower other operating costs (due~~CEI’s $216 million regulatory asset impairment related to the ~~assignment~~implementation of ~~leasehold interests in generating assets to FGCO),~~its ESP and increased purchased power costs, partially offset by ~~lower revenues and~~higher deferrals of new regulatory ~~asset deferrals and higher purchased power costs and regulatory asset amortization.~~assets.

Revenues

Revenues ~~decreased~~increased by ~~$24~~$12 million, or ~~1.7%~~2.8%, in the first ~~nine~~three months of ~~2008~~2009 compared to the same period of ~~2007,~~2008 primarily due to ~~a decrease~~an increase in ~~wholesale~~retail generation revenues ($8918 million), partially offset by ~~increases~~decreases in ~~retail generation revenues ($50 million),~~ distribution revenues ($84 million), and ~~transmission~~other miscellaneous revenues ($112 million).

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

Retail generation revenues increased in the first ~~nine~~three months of ~~2008~~2009 due to higher average unit prices across all customer classes ~~partially offset by a slight decrease in~~and increased sales volume ~~in all sectors~~to residential and commercial customers, compared to the same period of ~~2007. The higher average unit prices were driven by~~2008. Generation rate increases under CEI’s CBP contributed to the ~~2008 fuel cost recovery rider that became effective January 16, 2008~~increased rate variances (see Regulatory ~~Matters)~~Matters – Ohio). ~~Milder weather in the first nine months of 2008, compared~~Reduced industrial KWH sales, principally to ~~the same period of 2007, primarily caused the decrease~~major automotive and steel customers, reflected weakened economic conditions. The increase in sales volume ~~(heating~~for residential and ~~cooling degree days decreased 1% and 7%, respectively).~~commercial customers primarily reflected a decrease in customer shopping, as most of CEI’s customers returned to PLR service in December 2008.

Changes in retail generation sales and revenues in the first ~~nine~~three months of ~~2008~~2009 compared to the same period in ~~2007~~2008 are summarized in the following tables:

Retail Generation KWH Sales	~~Decrease~~ Increase (Decrease)

Residential		~~(1.2~~8.0	)%
Commercial		~~(1.1~~12.5	)%
Industrial		(~~1.1~~9.8	)%
~~Decrease~~ Net Increase in Retail Generation Sales		~~(1.1~~1.4	)%

Retail Generation Revenues Increase
(In millions)
Residential $ 17
Commercial 12
Industrial 21
Increase in Generation Revenues $ 50

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

Revenues from distribution throughput ~~increased~~decreased by $8$4 million in the first ~~nine~~three months of ~~2008~~2009 compared to the same period of ~~2007~~2008 primarily due to higher average unit prices for all customer classes, partially offset by a slight decrease in KWH deliveries in all sectors. The higher average unit prices resulted from transmission rider increases that became effective July 1, 2007 and July 1, 2008. The lower KWH deliveries to commercial and industrial customers as a result of the economic downturn in ~~the first nine months of 2008 reflected the weather impacts described above.~~CEI’s service territory.

~~Changes~~

Decreases in distribution KWH deliveries and revenues in the first ~~nine~~three months of ~~2008~~2009 compared to the same period of ~~2007~~2008 are summarized in the following tables.

Distribution KWH Deliveries	Decrease

Residential		(~~1.5~~0.6	)%
Commercial		(~~1.4~~5.1	)%
Industrial		(~~1.0~~19.8	)%
Decrease in Distribution Deliveries		(~~1.2~~10.0	)%

Distribution Revenues Increase
(In millions)
Residential $ -
Commercial 2
Industrial 6
Increase in Distribution Revenues $ 8

Transmission revenues were higher in the first nine months of 2008, compared to the same period of 2007, due to increased auction revenue rights for transmission service in MISO. CEI defers the difference between revenue from its transmission rider and net transmission costs incurred in MISO, resulting in no material effect to current period earnings.

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

Expenses

Total expenses ~~decreased~~increased by ~~$19~~$267 million in the first ~~nine~~three months of ~~2008~~2009 compared to the same period of ~~2007.~~2008. The following table presents the change from the prior year by expense category:

Expenses - Changes
Increase
(Decrease)

(In millions)
Fuel costs $ (40 )
Purchased power costs 15
Other operating costs (49 )
Provision for depreciation (1 )
Amortization of regulatory assets 15
Deferral of new regulatory assets 43
General taxes (2 )
Net Decrease in Expenses $ (19 )

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

The absence of fuel costs in the first nine months of 2008 was due to the assignment of CEI’s leasehold interests in the Mansfield Plant to FGCO in October 2007. Prior to the assignment, CEI incurred fuel expenses and other operating costs related to its leasehold interest in the plant.

Higher purchased power costs ~~reflected higher unit prices, as provided for under the PSA with FES, partially offset by a decrease in volume due to lower KWH sales. Other operating costs were lower~~are primarily due to the ~~assignment~~results of ~~CEI’s leasehold interests~~the CBP used for the procurement of electric generation for retail customers in the ~~Mansfield plant as described above, partially offset by higher labor costs resulting from storm restoration work performed during the~~ first ~~nine months~~quarter of ~~2008. Higher~~2009. Increased amortization of regulatory assets was primarily due to ~~increased transition cost amortization ($11 million) under~~ the ~~effective interest methodology and increased amortization~~impairment of ~~MISO transmission cost deferrals ($4 million).~~CEI’s Extended RTC balance in accordance with the PUCO-approved ESP. The ~~decrease~~increase in the deferral of new regulatory assets was primarily due to CEI’s deferral of purchased power costs as approved by the PUCO, partially offset by lower deferred MISO ~~cost~~transmission expenses and the absence of RCP distribution deferrals ~~($19 million) and RCP fuel costs ($25 million), as more transmission and generation~~that ceased at the end of 2008. While other operating costs were ~~recovered~~unchanged from ~~customers through PUCO-approved riders. General taxes decreased primarily due to a $3 million~~the previous year, cost increases associated with the ESP for economic development and energy efficiency programs, higher pension expense and restructuring costs were completely offset by reduced transmission expense, labor, contractor costs and general business expense. The decrease in general ~~tax reserves, partially offset by $1 million increase in commercial activity taxes.~~

~~Other Expense~~

~~Other expense increased by $13 million in the first nine months of 2008 compared to the same period of 2007~~taxes is primarily due to lower investment income and miscellaneous income, partially offset by a reduction in interest expense. Lower investment income is primarily the result of principal repayments during 2007 on notes receivable from associated companies. The lower interest expense is primarily due to $489 million in long-term debt redemptions during 2007, partially offset by a new debt issuance of $250 million in March 2007. Miscellaneous income decreased primarily due to reduced life insurance investment values.property taxes.

Legal Proceedings

New Accounting Standards and Interpretations

6655

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of Directors of

The Cleveland Electric Illuminating Company:

We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of ~~September 30, 2008~~March 31, 2009 and the related consolidated statements of income, ~~and~~ comprehensive income and cash flows for each of the three-month ~~and nine-month~~ periods ended ~~September 30, 2008~~March 31, 2009 and ~~2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007.~~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, ~~2007,~~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 ~~28, 2008,~~24, 2009, we expressed an unqualified opinion on those consolidated financial statements. ~~In our opinion, the information set forth~~As discussed in Note 6 to the accompanying consolidated ~~balance sheet information as of~~financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, ~~2007, is fairly stated in all material respects in relation to the~~2008 consolidated balance sheet ~~from which it has been derived.~~

reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

~~November 6, 2008~~May 7, 2009

6756

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Nine Months
Ended September 30 Ended Septmeber 30

2008 2007 2008 2007
(In thousands)

REVENUES:
Electric sales $ 505,425 $ 510,577 $ 1,342,327 $ 1,366,396
Excise tax collections 18,652 18,514 53,447 53,009
Total revenues 524,077 529,091 1,395,774 1,419,405

EXPENSES:
Fuel - 12,160 - 39,683
Purchased power 211,445 216,194 590,300 575,520
Other operating costs 66,342 85,114 194,119 243,140
Provision for depreciation 17,677 18,913 54,497 56,094
Amortization of regulatory assets 48,155 42,077 124,936 110,253
Deferral of new regulatory assets (16,176 ) (37,692 ) (71,443 ) (114,708 )
General taxes 36,722 37,930 109,230 110,922
Total expenses 364,165 374,696 1,001,639 1,020,904

OPERATING INCOME 159,912 154,395 394,135 398,501

OTHER INCOME (EXPENSE):
Investment income 8,390 13,805 25,972 47,816
Miscellaneous income (expense) (1,114 ) (760 ) (1,319 ) 3,197
Interest expense (31,024 ) (34,423 ) (94,479 ) (107,430 )
Capitalized interest 200 309 584 655
Total other expense (23,548 ) (21,069 ) (69,242 ) (55,762 )

INCOME BEFORE INCOME TAXES 136,364 133,326 324,893 342,739

INCOME TAXES 42,977 54,610 107,082 131,525

NET INCOME 93,387 78,716 217,811 211,214

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (213 ) 1,202 (639 ) 3,607
Income tax expense (benefit) related to other comprehensive income (130 ) 356 (239 ) 1,068
Other comprehensive income (loss), net of tax (83 ) 846 (400 ) 2,539

TOTAL COMPREHENSIVE INCOME $ 93,304 $ 79,562 $ 217,411 $ 213,753

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 STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

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

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

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

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

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

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

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

Less: Noncontrolling interest income		458			584

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

STATEMENTS OF COMPREHENSIVE INCOME

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

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

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

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		458			584

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

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

6857

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY							THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED BALANCE SHEETS	CONSOLIDATED BALANCE SHEETS							CONSOLIDATED BALANCE SHEETS
(Unaudited)	(Unaudited)							(Unaudited)
		September 30,			December 31,			March 31,				December 31,
		2008			2007				2009			2008
		(In thousands)						(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	237		$	232			$	233		$	226
Receivables-
Customers (less accumulated provisions of $6,907,000 and $7,540,000
respectively, for uncollectible accounts)			292,735			251,000
Customers (less accumulated provisions of $6,199,000 and
$5,916,000, respectively, for uncollectible accounts)										283,967			276,400
Associated companies			122,210			166,587				159,819			113,182
Other			4,151			12,184				4,438			13,834
Notes receivable from associated companies			21,682			52,306				22,744			19,060
Prepayments and other			2,373			2,327				2,002			2,787
			443,388			484,636				473,203			425,489
UTILITY PLANT:
In service			2,180,347			2,256,956				2,240,065			2,221,660
Less - Accumulated provision for depreciation			836,058			872,801				852,393			846,233
			1,344,289			1,384,155				1,387,672			1,375,427
Construction work in progress			44,392			41,163				40,545			40,651
			1,388,681			1,425,318				1,428,217			1,416,078
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			425,717			463,431				388,647			425,715
Other			10,260			10,285				10,239			10,249
			435,977			473,716				398,886			435,964
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			1,688,521			1,688,521				1,688,521			1,688,521
Regulatory assets			796,475			870,695				617,967			783,964
Pension assets			68,548			62,471
Property taxes			76,000			76,000				71,500			71,500
Other			9,036			32,987				10,629			10,818
			2,638,580			2,730,674				2,388,617			2,554,803
		$	4,906,626		$	5,114,344			$	4,688,923		$	4,832,334
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	207,312		$	207,266			$	150,704		$	150,688
Short-term borrowings-
Associated companies			367,422			531,943				242,065			227,949
Accounts payable-
Associated companies			124,335			169,187				94,824			106,074
Other			5,704			5,295				26,914			7,195
Accrued taxes			70,515			94,991				76,130			87,810
Accrued interest			37,885			13,895				41,546			13,932
Other			41,366			34,350				44,021			40,095
			854,539			1,056,927				676,204			633,743
CAPITALIZATION:
Common stockholder's equity-
Common stockholder's equity
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding			878,199			873,536				878,680			878,785
Accumulated other comprehensive loss			(69,529	)		(69,129	)			(132,260	)		(134,857	)
Retained earnings			793,238			685,428				754,096			859,954
Total common stockholder's equity			1,601,908			1,489,835				1,500,516			1,603,882
Noncontrolling interest										20,173			22,555
Total equity										1,520,689			1,626,437
Long-term debt and other long-term obligations			1,447,718			1,459,939				1,573,241			1,591,586
			3,049,626			2,949,774				3,093,930			3,218,023
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			727,615			725,523				644,547			704,270
Accumulated deferred investment tax credits			13,442			18,567				12,731			13,030
Retirement benefits			95,931			93,456				129,537			128,738
Deferred revenues - electric service programs			9,594			27,145
Lease assignment payable to associated companies			40,827			131,773				40,827			40,827
Other			115,052			111,179				91,147			93,703
			1,002,461			1,107,643				918,789			980,568
COMMITMENTS AND CONTINGENCIES (Note 11)
COMMITMENTS AND CONTINGENCIES (Note 8)
									$	4,688,923		$	4,832,334
		$	4,906,626		$	5,114,344

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

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31

	2009			2008

	(In thousands)

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

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

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

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


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

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months
Ended September 30
2008 2007
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 217,811 $ 211,214
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 54,497 56,094
Amortization of regulatory assets 124,936 110,253
Deferral of new regulatory assets (71,443 ) (114,708 )
Deferred rents and lease market valuation liability - (46,327 )
Deferred income taxes and investment tax credits, net 4,623 (40,964 )
Accrued compensation and retirement benefits (3,291 ) 2,575
Pension trust contribution - (24,800 )
Decrease (increase) in operating assets-
Receivables 43,927 140,359
Prepayments and other current assets (37 ) 661
Increase (decrease) in operating liabilities-
Accounts payable (44,443 ) (143,210 )
Accrued taxes (19,613 ) 17,301
Accrued interest 23,990 22,360
Electric service prepayment programs (17,551 ) (16,819 )
Other 4,193 2,996
Net cash provided from operating activities 317,599 176,985

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt - 247,424
Redemptions and Repayments-
Long-term debt (508 ) (223,555 )
Short-term borrowings, net (176,354 ) (59,328 )
Dividend Payments-
Common stock (110,000 ) (304,000 )
Net cash used for financing activities (286,862 ) (339,459 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (97,326 ) (100,583 )
Loan repayments from (loans to) associated companies, net 30,624 (13,863 )
Collection of principal on long-term notes receivable - 220,974
Redemption of lessor notes 37,714 56,177
Other (1,744 ) (218 )
Net cash provided from (used for) investing activities (30,732 ) 162,487

Net increase in cash and cash equivalents 5 13
Cash and cash equivalents at beginning of period 232 221
Cash and cash equivalents at end of period $ 237 $ 234

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

7059

THE TOLEDO EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. ~~TE’s~~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 ~~requirements are provided by FES – an affiliated company.~~procurement issues for 2009 and beyond.

Results of Operations

Net income in the first ~~nine~~three months of ~~2008~~2009 decreased to ~~$70~~$1 million from ~~$73~~$17 million in the same period of ~~2007.~~2008. The decrease resulted primarily from ~~lower electric sales revenues, higher purchased power costs and a decrease~~the completion of transition cost recovery in ~~the deferral of new regulatory assets, partially offset by lower other operating costs.~~2008.

Revenues

Revenues ~~decreased $66~~increased $33 million, or ~~8.8%~~15.6%, in the first ~~nine~~three months of ~~2008,~~2009 compared to the same period of ~~2007,~~2008 primarily due to ~~lower wholesale~~increased retail generation revenues ($~~114~~67 million), partially offset by ~~increased retail~~lower distribution revenues ($33 million) and wholesale generation revenues ($~~37 million), distribution revenues ($5 million) and transmission revenues ($6~~1 million).

The decrease in wholesale revenues was primarily due to lower associated company sales of KWH from TE’s leasehold interests in generating plants. Revenues from TE’s leasehold interests in Beaver Valley Unit 2 decreased by $50 million due to the unit’s 39-day refueling outage in the second quarter of 2008 and the incremental pricing impacts related to the termination of TE’s sale agreement with CEI. At the end of 2007, TE terminated its Beaver Valley Unit 2 output sale agreement with CEI and is currently selling the 158 MW entitlement from its 18.26% leasehold interest in the unit to NGC. Revenues from PSA sales decreased by $67 million in the first nine months of 2008 due to the assignment of TE’s leasehold interests in the Bruce Mansfield Plant to FGCO in October 2007. Prior to the assignment, TE sold power from its interests in the plant to FGCO.

Retail generation revenues increased in the first ~~nine~~three months of ~~2008~~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 ~~2007. The higher average prices were driven by~~2008. TE’s implementation of a fuel rider in January 2009 produced the ~~2008 fuel cost recovery rider that became effective January 16, 2008~~rate variances (see Regulatory ~~Matters)~~Matters – Ohio). ~~Sales~~Reduced industrial KWH sales, principally to ~~residential~~major automotive and steel customers, ~~decreased due to milder weather in the first nine months of 2008 (cooling degree days decreased 15% from the same period of 2007).~~reflected weakened economic conditions. The increase in sales tovolume for residential and commercial customers ~~was due to less~~resulted principally from a decrease in customer ~~shopping; generation services provided by alternative suppliers as a percentage~~shopping. Most of ~~total sales delivered in~~ TE’s franchise ~~area decreased by three percentage points. Industrial KWH sales decreased due~~customers returned to PLR service in ~~part to lower sales to the automotive sector and a maintenance outage undertaken by a large industrial customer during the first nine months of~~December 2008.

Changes in retail electric generation KWH sales and revenues in the first ~~nine~~three months of ~~2008~~2009 from the same period of ~~2007~~2008 are summarized in the following tables.

	Increase
Retail ~~Generation~~ KWH Sales	(Decrease)

Residential		~~(1.3~~6.5	)%
Commercial		~~4.9~~39.3	%
Industrial		(~~4.8~~11.5	)%
Net ~~Decrease~~Increase in Retail ~~Generation~~KWH Sales		~~(2.0~~3.9	)%

Retail Generation Revenues Increase

(In millions)

Residential $ 7
Commercial 11
Industrial 19
Increase in Retail Generation Revenues $ 37

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

Revenues from distribution throughput ~~increased~~decreased by $5$33 million in the first ~~nine~~three months of ~~2008~~2009 compared to the same period in ~~2007~~2008 due to ~~higher~~lower average unit prices and lower KWH deliveries for all customer ~~classes,~~classes. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by ~~lower KWH deliveries to all sectors. The higher average prices resulted from~~a PUCO-approved transmission rider increases that became effective July 1, 2007 and July 1, 2008. The lower KWH deliveries to residential and commercial customers in the first nine months of 2008 reflected the weather impacts described above. As with the reduction in generation sales, industrial KWH deliveries decreased in part due to lower sales to the automotive sector and a maintenance outage undertaken by a large industrial customer in 2008.

distribution rate increase (see Regulatory Matters – Ohio).

Changes in distribution KWH deliveries and revenues in the first ~~nine~~three months of ~~2008~~2009 from the same period of ~~2007~~2008 are summarized in the following tables.

Distribution KWH Deliveries	Decrease

Residential		(~~1.8~~2.8	)%
Commercial		(~~0.5~~10.0	)%
Industrial		(~~4.7~~13.5	)%
Decrease in Distribution Deliveries		(~~2.8~~9.6	)%

Distribution Revenues Increase
(In millions)
   Residential $ 2
   Commercial 2
   Industrial 1
   Increase in Distribution Revenues $ 5

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

Expenses

Total expenses ~~decreased $40~~increased $57 million in the first ~~nine~~three months of ~~2008~~2009 from the same period of ~~2007.~~2008. The following table presents changes from the prior year by expense category.

Expenses – Changes Increase (Decrease)
(In millions)
Purchased power costs $
11

Other operating costs

(76
)
Provision for depreciation

(3
)
Amortization of regulatory assets

3

Deferral of new regulatory assets

23

General taxes

2

Net Decrease in Expenses

$
(40
)

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

Higher purchased power costs ~~primarily reflected higher unit prices as provided for under the PSA with FES. Other operating costs decreased~~are primarily due to the ~~reversal~~results of the ~~above-market lease liability ($23 million) associated with TE’s leasehold interest in Beaver Valley Unit 2, as a result~~CBP used for the procurement of electric generation for retail customers during the ~~termination~~first quarter of ~~the CEI sale agreement described above, and lower fuel costs ($25 million) and~~2009. While other operating costs ~~($28 million) due to~~were unchanged from the ~~assignment~~first quarter of ~~TE’s leasehold interests in~~2008, cost increases associated with the ~~Mansfield Plant in October 2007. These decreases~~regulatory obligations for economic development and energy efficiency programs, higher pension and other expenses were ~~partially~~completely offset by ~~increased costs ($7 million) associated with TE’s leasehold interests in Beaver Valley Unit 2, due to a refueling outage in the second quarter of 2008.~~reduced transmission, labor and other employee benefit expenses. Depreciation expense decreased ~~primarily~~ due to the transfer of leasehold improvements for the Bruce Mansfield Plant and Beaver Valley Unit 2 to FGCO and NGC, respectively, during ~~the first nine months of~~ 2008.

The ~~increase~~decrease in the net amortization of regulatory assets ~~was~~is primarily due to ~~increased~~the cessation of transition cost amortization, ~~of MISO transmission cost deferrals ($5 million),~~ partially offset by ~~lower amortization~~a reduction in transmission deferrals and the absence of transition cost deferrals ($2 million) resulting from reduced distribution deliveries. The change in the deferral of new regulatory assets was primarily due to lower deferred fuel costs ($11 million) and MISO transmission expenses ($7 million), as more generation and transmission costs were recovered from customers through PUCO-approved riders, and lower RCP distribution cost deferrals ~~($4 million). Higher general taxes primarily reflected increased KWH taxes, property taxes and Ohio commercial activity taxes.~~

~~Other Expense~~

~~Other expense decreased $6 million~~ in the first nine months of 2008, compared to the same period of 2007, primarily due to lower interest expense, partially offset by lower investment income. The lower interest expense resulted from lower money pool borrowings from associated companies in the first nine months of 2008, and the redemption of long-term debt ($55 million principal amount) since the third quarter of 2007. The decrease in investment income resulted primarily from principal repayments since the third quarter of 2007 on notes receivable from associated companies and lower interest income from customer accounts receivable financing activity.

2009.

Legal Proceedings

New Accounting Standards and Interpretations

7361

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of The Toledo Edison Company:

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of ~~September 30, 2008~~March 31, 2009 and the related consolidated statements of income, ~~and~~ comprehensive income and cash flows for each of the three-month ~~and nine-month~~ periods ended ~~September 30, 2008~~March 31, 2009 and ~~2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007.~~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, ~~2007,~~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 ~~28, 2008,~~24, 2009, we expressed an unqualified opinion on those consolidated financial statements. ~~In our opinion, the information set forth~~As discussed in Note 6 to the accompanying consolidated ~~balance sheet information as of~~financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, ~~2007, is fairly stated in all material respects in relation to the~~2008 consolidated balance sheet ~~from which it has been derived.~~

reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

~~November 6, 2008~~May 7, 2009

7462

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
(In thousands)

REVENUES:
Electric sales $ 242,866 $ 261,736 $ 660,888 $ 728,429
Excise tax collections 8,239 7,926 23,417 22,026
Total revenues 251,105 269,662 684,305 750,455

EXPENSES:
Purchased power 111,809 112,502 315,957 304,947
Other operating costs 47,010 73,701 143,144 218,961
Provision for depreciation 7,682 9,231 24,648 27,475
Amortization of regulatory assets 31,452 30,460 81,837 79,284
Deferral of new regulatory assets (5,574 ) (15,645 ) (23,997 ) (47,373 )
General taxes 13,609 11,912 40,591 38,646
Total expenses 205,988 222,161 582,180 621,940

OPERATING INCOME 45,117 47,501 102,125 128,515

OTHER INCOME (EXPENSE):
Investment income 5,580 6,721 17,285 21,255
Miscellaneous expense (1,529 ) (2,153 ) (4,992 ) (7,309 )
Interest expense (5,832 ) (8,786 ) (17,445 ) (25,205 )
Capitalized interest 19 220 144 467
Total other expense (1,762 ) (3,998 ) (5,008 ) (10,792 )

INCOME BEFORE INCOME TAXES 43,355 43,503 97,117 117,723

INCOME TAXES 12,174 18,435 27,614 44,924

NET INCOME 31,181 25,068 69,503 72,799

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (64 ) 574 (191 ) 1,720
Change in unrealized gain on available-for-sale-securities (247 ) 1,946 (767 ) 1,656
Other comprehensive income (loss) (311 ) 2,520 (958 ) 3,376
Income tax expense (benefit) related to other
comprehensive income (108 ) 902 (294 ) 1,193
Other comprehensive income (loss), net of tax (203 ) 1,618 (664 ) 2,183

TOTAL COMPREHENSIVE INCOME $ 30,978 $ 26,686 $ 68,839 $ 74,982

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 STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

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

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

OPERATING INCOME		2,230			26,134

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

INCOME BEFORE INCOME TAXES		883			25,105

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

NET INCOME		992			17,017

Less: Noncontrolling interest income		2			2

EARNINGS AVAILABLE TO PARENT	$	990		$	17,015

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	992		$	17,017

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

COMPREHENSIVE INCOME		335			18,187

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		2			2

COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT	$	333		$	18,185

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

7563

THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2008 2007
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 24 $ 22
Receivables-
Customers 931 449
Associated companies 58,215 88,796
Other (less accumulated provisions of $165,000 and $615,000,
respectively, for uncollectible accounts) 15,810 3,116
Notes receivable from associated companies 111,519 154,380
Prepayments and other 1,421 865
187,920 247,628
UTILITY PLANT:
In service 860,417 931,263
Less - Accumulated provision for depreciation 402,952 420,445
457,465 510,818
Construction work in progress 7,626 19,740
465,091 530,558
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes 142,657 154,646
Long-term notes receivable from associated companies 37,308 37,530
Nuclear plant decommissioning trusts 68,438 66,759
Other 1,691 1,756
250,094 260,691
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 500,576 500,576
Regulatory assets 145,404 203,719
Pension assets 31,059 28,601
Property taxes 21,010 21,010
Other 52,325 20,496
750,374 774,402
$ 1,653,479 $ 1,813,279
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 34 $ 34
Accounts payable-
Associated companies 88,769 245,215
Other 3,368 4,449
Notes payable to associated companies 95,203 13,396
Accrued taxes 20,508 30,245
Lease market valuation liability 36,900 36,900
Other 26,415 22,747
271,197 352,986
CAPITALIZATION:
Common stockholder's equity-
Common stock, $5 par value, authorized 60,000,000 shares -
29,402,054 shares outstanding 147,010 147,010
Other paid-in capital 175,643 173,169
Accumulated other comprehensive loss (11,270 ) (10,606 )
Retained earnings 185,121 175,618
Total common stockholder's equity 496,504 485,191
Long-term debt and other long-term obligations 303,382 303,397
799,886 788,588
NONCURRENT LIABILITIES:
Accumulated deferred income taxes 100,872 103,463
Accumulated deferred investment tax credits 6,882 10,180
Lease market valuation liability 282,325 310,000
Retirement benefits 66,201 63,215
Asset retirement obligations 29,715 28,366
Deferred revenues - electric service programs 4,073 12,639
Lease assignment payable to associated companies 30,529 83,485
Other 61,799 60,357
582,396 671,705
COMMITMENTS AND CONTINGENCIES (Note 11)
$ 1,653,479 $ 1,813,279

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

THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,				December 31,
		2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	15		$	14
Receivables-
Customers			438			751
Associated companies			70,444			61,854
Other (less accumulated provisions of $193,000 and $203,000,
respectively, for uncollectible accounts)			23,693			23,336
Notes receivable from associated companies			133,186			111,579
Prepayments and other			4,481			1,213
			232,257			198,747
UTILITY PLANT:
In service			880,315			870,911
Less - Accumulated provision for depreciation			413,030			407,859
			467,285			463,052
Construction work in progress			10,957			9,007
			478,242			472,059
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			124,329			142,687
Long-term notes receivable from associated companies			37,154			37,233
Nuclear plant decommissioning trusts			73,235			73,500
Other			1,646			1,668
			236,364			255,088
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			500,576			500,576
Regulatory assets			96,351			109,364
Property taxes			22,970			22,970
Other			62,004			51,315
			681,901			684,225
		$	1,628,764		$	1,610,119
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	222		$	34
Accounts payable-
Associated companies			59,462			70,455
Other			14,823			4,812
Notes payable to associated companies			107,265			111,242
Accrued taxes			23,259			24,433
Lease market valuation liability			36,900			36,900
Other			54,397			22,489
			296,328			270,365
CAPITALIZATION:
Common stockholder's equity-
Common stock, $5 par value, authorized 60,000,000 shares -
29,402,054 shares outstanding			147,010			147,010
Other paid-in capital			175,866			175,879
Accumulated other comprehensive loss			(34,029	)		(33,372	)
Retained earnings			191,523			190,533
Total common stockholder's equity			480,370			480,050
Noncontrolling interest			2,676			2,675
Total equity			483,046			482,725
Long-term debt and other long-term obligations			303,021			299,626
			786,067			782,351
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			77,016			78,905
Accumulated deferred investment tax credits			6,695			6,804
Lease market valuation liability			263,875			273,100
Retirement benefits			74,911			73,106
Asset retirement obligations			30,719			30,213
Lease assignment payable to associated companies			30,529			30,529
Other			62,624			64,746
			546,369			557,403
COMMITMENTS AND CONTINGENCIES (Note 8)
		$	1,628,764		$	1,610,119

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

7664

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months
Ended September 30
2008 2007
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 69,503 $ 72,799
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 24,648 27,475
Amortization of regulatory assets 81,837 79,284
Deferral of new regulatory assets (23,997 ) (47,373 )
Deferred rents and lease market valuation liability (32,918 ) (23,551 )
Deferred income taxes and investment tax credits, net (4,163 ) (32,530 )
Accrued compensation and retirement benefits (196 ) 3,493
Pension trust contribution - (7,659 )
Decrease (increase) in operating assets-
Receivables 29,088 (13,368 )
Prepayments and other current assets (556 ) 224
Increase (decrease) in operating liabilities-
Accounts payable (157,527 ) 9,515
Accrued taxes (9,737 ) 13,588
Accrued interest 4,663 3,444
Electric service prepayment programs (8,566 ) (7,650 )
Other (577 ) 4,113
Net cash provided from (used for) operating activities (28,498 ) 81,804

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net 81,807 37,191
Redemptions and Repayments-
Long-term debt (26 ) (30,014 )
Dividend Payments-
Common stock (60,000 ) (120,000 )
Net cash provided from (used for) financing activities 21,781 (112,823 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (44,695 ) (41,573 )
Loan repayments from associated companies, net 42,948 21,438
Collection of principal on long-term notes receivable 135 36,077
Redemption of lessor notes 11,989 14,819
Sales of investment securities held in trusts 28,774 39,260
Purchases of investment securities held in trusts (31,297 ) (41,717 )
Other (1,135 ) 2,713
Net cash provided from investing activities 6,719 31,017

Net increase (decrease) in cash and cash equivalents 2 (2 )
Cash and cash equivalents at beginning of period 22 22
Cash and cash equivalents at end of period $ 24 $ 20

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 STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)

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

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

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

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

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

7765

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also provides generation services to ~~those~~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 ~~nine~~three months of ~~2008~~2009 decreased to ~~$153~~$28 million from ~~$164~~$34 million in the same period in ~~2007.~~2008. The decrease was primarily due to lower revenues and higher other operating costs, partially offset by lower purchased power costs and ~~other expenses, partially offset by higher revenues and lower~~reduced amortization of regulatory assets.

Revenues

In the first ~~nine~~three months of ~~2008,~~2009, revenues ~~increased $235~~decreased by $21 million, or 9%3%, as compared ~~with~~to the same period of ~~2007. Retail and wholesale~~2008. A $31 million increase in retail generation revenues ~~increased~~was more than offset by ~~$147~~a $47 million ~~and $97 million, respectively, while distribution~~decrease in wholesale revenues ~~decreased by $3 million~~ in the first ~~nine~~three months of ~~2008.~~2009.

Retail generation revenues from all customer classes increased in the first three months of 2009 compared to the same period of 2008 due to higher unit prices resulting from the BGS ~~auctions~~auction effective ~~June 1, 2007, and~~ June 1, 2008, partially offset by ~~decreased~~a decrease in retail generation KWH ~~sales. The~~sales to commercial customers. Sales volume to the commercial sector decreased primarily due to an increase in the number of customers procuring generation from other suppliers.

Wholesale generation revenues decreased $47 million in the first three months of 2009 due to lower market prices and a decrease in sales volume ~~was primarily caused by milder weather and customer shopping. In the first nine months of 2008, heating degree days decreased 8.1%~~(from NUG purchases) as compared to the first nine months of 2007, while cooling degree days were unchanged. Customer shopping in the commercial and industrial customer sectors increased by 3.7 percentage points and 1.3 percentage points, respectively, in the first ninethree months of 2008.

Changes in retail generation KWH sales and revenues by customer class in the first ~~nine~~three months of ~~2008~~2009 compared to the same period of ~~2007~~2008 are summarized in the following tables:

Retail Generation KWH Sales	Increase ~~Decrease~~(Decrease)

Residential		~~(1.2)~~0.1	%
Commercial		~~(6.0)~~(7.0	)%
Industrial		~~(6.7)~~2.9	%
Net Decrease in Generation Sales		~~(3.4)~~(2.7	)%

Retail Generation Revenues Increase
(In millions)
Residential $ 99
Commercial 42
Industrial 6
Increase in Generation Revenues $ 147

Wholesale generation revenues increased $97 million in the first nine months of 2008 due to higher market prices, partially offset by a slight decrease in sales volumes as compared to the first nine months of 2007.

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

Distribution revenues decreased $3by $1 million in the first ~~nine~~three months of ~~2008 as~~2009 compared to the same period of ~~2007 due to~~2008, reflecting lower KWH deliveries ~~reflecting the weather impacts described above,~~to commercial and industrial customers as a result of weakened economic conditions in JCP&L’s service territory. The decrease in KWH deliveries was partially offset by ~~a slight~~an increase in composite unit prices.

Changes in distribution KWH deliveries and revenues by customer class in the first ~~nine~~three months of ~~2008~~2009 compared to the same period in ~~2007~~2008 are summarized in the following tables:

	Increase
Distribution KWH Deliveries	~~Decrease~~(Decrease)

Residential	~~(1.2)~~	-	%
Commercial	~~(1.4)~~	(2.4	)%
Industrial	~~(1.5)~~	(11.4	)%
Decrease in Distribution Deliveries	~~(1.3)~~	(2.5	)%

7866

Distribution Revenues
Increase
(Decrease)

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

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

Expenses

Total expenses ~~increased~~decreased by ~~$236~~$11 million in the first ~~nine~~three months of ~~2008 as~~2009 compared to the same period of ~~2007.~~2008. The following table presents changes from the prior year period by expense category:

Expenses - Changes
Increase
(Decrease)

(In millions)
Purchased power costs $ 246
Other operating costs (1 )
Provision for depreciation 6
Amortization of regulatory assets (16 )
General taxes 1
Net increase in expenses $ 236

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

Purchased power costs decreased in the first three months of 2009 primarily due to lower KWH purchases to meet the lower demand, partially offset by higher unit prices from the BGS auction effective June 1, 2008. Other operating costs increased in the first ~~nine~~three months of ~~2008~~2009 primarily due to higher ~~unit prices resulting from the BGS auctions effective June 1, 2007,~~expenses related to employee benefits and ~~June 1, 2008,~~customer assistance programs, partially offset by ~~a decrease in purchases due to the~~ lower ~~generation KWH sales discussed above.~~contracting and labor expenses. Depreciation expense increased primarily due to an increase in depreciable property since the ~~third~~first quarter of ~~2007.~~2008. Amortization of regulatory assets decreased in the first ~~nine~~three months of ~~2008~~2009 primarily due to the ~~completion in December 2007~~full recovery of certain regulatory ~~asset amortizations associated with TMI-2 and lower transition cost amortization due to the lower KWH deliveries discussed above.~~assets in June 2008.

Other Expenses

Other expenses increased by ~~$13~~$2 million in the first ~~nine~~three months of ~~2008 as~~2009 compared to the same period in ~~2007~~2008 primarily due to interest expense associated with JCP&L’s ~~$550~~$300 million Senior Notes issuance ~~of senior notes~~ in ~~May 2007 and reduced life insurance investment values.~~

~~Sale of Investment~~January 2009.

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

Legal Proceedings

New Accounting Standards and Interpretations

7967

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Jersey Central Power & Light Company:

We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of ~~September 30, 2008~~March 31, 2009 and the related consolidated statements of income, ~~and~~ comprehensive income and cash flows for each of the three-month ~~and nine-month~~ periods ended ~~September 30, 2008~~March 31, 2009 and ~~2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007.~~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, ~~2007,~~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 ~~28, 2008,~~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, ~~2007,~~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

~~November 6, 2008~~May 7, 2009

8068

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)

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

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

OPERATING INCOME		77,110			86,934

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

INCOME BEFORE INCOME TAXES		50,109			62,357

INCOME TAXES		22,551			28,403

NET INCOME		27,558			33,954

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

TOTAL COMPREHENSIVE INCOME	$	30,318		$	32,044

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

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
(In thousands)

REVENUES:
Electric sales $ 1,087,245 $ 1,018,049 $ 2,691,782 $ 2,457,146
Excise tax collections 15,358 15,168 39,792 39,849
Total revenues 1,102,603 1,033,217 2,731,574 2,496,995

EXPENSES:
Purchased power 720,996 654,418 1,751,854 1,505,420
Other operating costs 78,275 87,010 234,628 236,225
Provision for depreciation 23,205 22,032 70,030 63,867
Amortization of regulatory assets 102,954 107,837 280,980 296,955
General taxes 19,476 18,631 52,042 51,183
Total expenses 944,906 889,928 2,389,534 2,153,650

OPERATING INCOME 157,697 143,289 342,040 343,345

OTHER INCOME (EXPENSE):
Miscellaneous income (expense) (565 ) 2,967 459 9,266
Interest expense (25,747 ) (24,666 ) (75,051 ) (71,576 )
Capitalized interest 257 483 963 1,559
Total other expense (26,055 ) (21,216 ) (73,629 ) (60,751 )

INCOME BEFORE INCOME TAXES 131,642 122,073 268,411 282,594

INCOME TAXES 55,752 46,275 115,623 118,637

NET INCOME 75,890 75,798 152,788 163,957

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (3,449 ) (2,114 ) (10,347 ) (6,344 )
Unrealized gain on derivative hedges 69 69 207 235
Other comprehensive loss (3,380 ) (2,045 ) (10,140 ) (6,109 )
Income tax benefit related to other comprehensive loss (1,469 ) (994 ) (4,408 ) (2,973 )
Other comprehensive loss, net of tax (1,911 ) (1,051 ) (5,732 ) (3,136 )

TOTAL COMPREHENSIVE INCOME $ 73,979 $ 74,747 $ 147,056 $ 160,821

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

8169

JERSEY CENTRAL POWER & LIGHT COMPANY	JERSEY CENTRAL POWER & LIGHT COMPANY							JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS	CONSOLIDATED BALANCE SHEETS							CONSOLIDATED BALANCE SHEETS
(Unaudited)	(Unaudited)							(Unaudited)
		September 30,			December 31,				March 31,			December 31,
		2008			2007				2009			2008
		(In thousands)							(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	38		$	94			$	4		$	66
Receivables-
Customers (less accumulated provisions of $4,115,000 and $3,691,000,
Customers (less accumulated provisions of $3,415,000 and $3,230,000
respectively, for uncollectible accounts)			386,037			321,026				315,084			340,485
Associated companies			45			21,297				116			265
Other			51,020			59,244				35,941			37,534
Notes receivable - associated companies			17,874			18,428				91,362			16,254
Prepaid taxes			81,540			1,012				4,243			10,492
Other			2,059			17,603				21,006			18,066
			538,613			438,704				467,756			423,162
UTILITY PLANT:
In service			4,297,036			4,175,125				4,337,711			4,307,556
Less - Accumulated provision for depreciation			1,547,099			1,516,997				1,562,417			1,551,290
			2,749,937			2,658,128				2,775,294			2,756,266
Construction work in progress			65,095			90,508				69,806			77,317
			2,815,032			2,748,636				2,845,100			2,833,583
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust			183,152			176,512				189,784			181,468
Nuclear plant decommissioning trusts			158,418			175,869				136,783			143,027
Other			2,176			2,083				2,154			2,145
			343,746			354,464				328,721			326,640
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill										1,810,936			1,810,936
Regulatory assets			1,295,024			1,595,662				1,162,132			1,228,061
Goodwill			1,814,976			1,826,190
Pension Assets			122,332			100,615
Other			14,959			16,307				28,487			29,946
			3,247,291			3,538,774				3,001,555			3,068,943
		$	6,944,682		$	7,080,578			$	6,643,132		$	6,652,328
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	28,713		$	27,206			$	29,465		$	29,094
Short-term borrowings-
Associated companies			142,617			130,381				-			121,380
Accounts payable-
Associated companies			10,541			7,541				22,562			12,821
Other			226,947			193,848				158,972			198,742
Accrued taxes										53,998			20,561
Accrued interest			26,594			9,318				30,446			9,197
Cash collateral from suppliers			23,510			583
Other			123,273			105,827				129,745			133,091
			582,195			474,704				425,188			524,886
CAPITALIZATION:
CAPITALIZATION
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares-
14,421,637 shares outstanding			144,216			144,216
13,628,447 shares outstanding										136,284			144,216
Other paid-in capital			2,648,732			2,655,941				2,502,594			2,644,756
Accumulated other comprehensive loss			(25,613	)		(19,881	)			(213,778	)		(216,538	)
Retained earnings			204,376			237,588				121,134			156,576
Total common stockholder's equity			2,971,711			3,017,864				2,546,234			2,729,010
Long-term debt and other long-term obligations			1,540,208			1,560,310				1,824,851			1,531,840
			4,511,919			4,578,174				4,371,085			4,260,850
NONCURRENT LIABILITIES:
Power purchase contract loss liability			602,626			749,671
Power purchase contract liability										530,538			531,686
Accumulated deferred income taxes			791,220			800,214				664,388			689,065
Nuclear fuel disposal costs			195,688			192,402				196,260			196,235
Asset retirement obligations			93,798			89,669				96,839			95,216
Retirement benefits										185,265			190,182
Other			167,236			195,744				173,569			164,208
			1,850,568			2,027,700				1,846,859			1,866,592
COMMITMENTS AND CONTINGENCIES (Note 11)
COMMITMENTS AND CONTINGENCIES (Note 8)
		$	6,944,682		$	7,080,578			$	6,643,132		$	6,652,328

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

8270

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months
Ended September 30
2008 2007
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 152,788 $ 163,957
Adjustments to reconcile net income to net cash from operating activities -
Provision for depreciation 70,030 63,867
Amortization of regulatory assets 280,980 296,955
Deferred purchased power and other costs (132,820 ) (157,201 )
Deferred income taxes and investment tax credits, net 1,051 (23,786 )
Accrued compensation and retirement benefits (32,087 ) (17,543 )
Cash collateral received from (returned to) suppliers 23,138 (32,243 )
Pension trust contribution - (17,800 )
Decrease (increase) in operating assets-
Receivables (43,742 ) (149,024 )
Materials and supplies 348 127
Prepaid taxes (62,148 ) (28,337 )
Other current assets (114 ) 2,079
Increase (decrease) in operating liabilities-
Accounts payable 36,099 (6,598 )
Accrued taxes 2,082 29,318
Accrued interest 17,276 13,062
Tax collections payable (12,493 ) (12,478 )
Other 24,705 2,534
Net cash provided from operating activities 325,093 126,889

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt - 549,999
Short-term borrowings, net 12,236 -
Redemptions and Repayments-
Long-term debt (19,138 ) (324,256 )
Short-term borrowings, net - (31,145 )
Common Stock - (125,000 )
Dividend Payments-
Common stock (186,000 ) (43,000 )
Net cash provided from (used for) financing activities (192,902 ) 26,598

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (136,265 ) (144,668 )
Proceeds from asset sales 20,000 -
Loan repayments from associated companies, net 553 1,722
Sales of investment securities held in trusts 186,564 169,649
Purchases of investment securities held in trusts (199,699 ) (181,794 )
Other (3,400 ) 1,640
Net cash used for investing activities (132,247 ) (153,451 )

Net increase (decrease) in cash and cash equivalents (56 ) 36
Cash and cash equivalents at beginning of period 94 41
Cash and cash equivalents at end of period $ 38 $ 77

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 STATEMENTS OF CASH FLOWS
(Unaudited)

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

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

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

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

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

8371

METROPOLITAN EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier. Met-Ed has a partial requirements wholesale power sales agreement with FES, to supply a portion of each of its default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty day written notice prior to the end of the calendar year.

Results of Operations

Net income decreased to ~~$64~~$17 million in the first ~~nine months~~quarter of ~~2008,~~2009, compared to ~~$76~~$22 million in the same period of ~~2007.~~2008. The decrease was primarily due to higher purchased power costs and ~~other operating costs,~~lower deferrals of new regulatory assets, partially offset by higher ~~revenues and deferrals of new regulatory assets.~~revenues.

Revenues

Revenues increased by ~~$105~~$29 million, or ~~9.2%~~7.3%, in the first ~~nine months~~quarter of 2009, compared to the same period of 2008, ~~principally~~primarily due to higher distribution throughput revenues and wholesale generation revenues, partially offset by a decrease in retail generation revenues. Wholesale revenues increased by ~~$96~~$8 million in the first ~~nine months~~quarter of ~~2008,~~2009, compared to the same period of ~~2007, primarily reflecting~~2008, due to higher ~~spot market~~capacity prices for PJM market ~~participants. Increased distribution throughput revenues were partially offset by decreases~~participants; wholesale KWH sales volume was lower in ~~retail generation revenues and PJM transmission revenues.~~2009.

In the first ~~nine months~~quarter of ~~2008,~~2009, retail generation revenues decreased $1$5 million ~~primarily~~ due to lower KWH sales to the ~~residential~~commercial and industrial customer classes, partially offset by higher KWH sales to ~~commercial customers and higher~~the residential customer class with a slight increase in composite unit prices in all customer classes. Higher KWH sales in the residential sector were due to increased weather- related usage, reflecting an 8.1% increase in heating degree days in the first quarter of 2009. Lower KWH sales to commercial and industrial customers were principally due to economic conditions in Met-Ed’s service territory.

Changes in retail generation sales and revenues in the first ~~nine months~~quarter of ~~2008~~2009 compared to the same period of ~~2007~~2008 are summarized in the following tables:

	Increase
Retail Generation KWH Sales	(Decrease)

Residential		~~(0.8~~2.9	)%
Commercial		~~1.8~~(2.5	)%
Industrial		(~~3.4~~12.9	)%
Net Decrease in Retail Generation Sales		(~~0.7~~2.9	)%

	Increase
Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	(12	)
Commercial		4(1	)
Industrial		(46	)
Net Decrease in Retail Generation Revenues	$	(15	)

~~Revenues from~~In the first quarter of 2009, distribution throughput revenues increased ~~$27~~$22 million ~~in the first nine months of 2008, compared~~primarily due to ~~the same period in 2007. Higher~~higher transmission rates, ~~received for transmission services,~~ resulting from the annual update of Met-Ed’s TSC rider effective June 1, ~~2008 (see Regulatory Matters), were partially offset by decreased distribution rates.~~2008. Decreased ~~KWH~~ deliveries ~~in the residential~~to commercial and industrial ~~customer classes~~customers, reflecting the weakened economy, were partially offset by increased ~~KWH~~ deliveries to ~~commercial customers.~~residential customers as a result of the weather conditions described above.

Changes in distribution KWH deliveries and revenues in the first ~~nine months~~quarter of ~~2008~~2009 compared to the same period of ~~2007~~2008 are summarized in the following tables:

	Increase
Distribution KWH Deliveries	(Decrease)

Residential		~~(0.8~~2.9	)%
Commercial		~~1.8~~(2.5	)%
Industrial		(~~3.4~~12.9	)%
Net Decrease in Distribution Deliveries		(~~0.7~~2.9	)%

Distribution Revenues	Increase
	(In millions)
Residential	$	1114
Commercial		115
Industrial		53
Increase in Distribution Revenues	$	2722

PJM transmission revenues ~~decreased~~increased by ~~$18~~$4 million in the first ~~nine months~~quarter of ~~2008~~2009 compared to the same period of ~~2007,~~2008, primarily due to ~~decreased PJM FTR revenue.~~increased revenues related to Met-Ed’s Auction Revenue Rights and Financial Transmission Rights. Met-Ed defers the difference between transmission revenues and ~~net~~ transmission costs incurred, ~~in PJM,~~ resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses increased by ~~$116~~$37 million in the first ~~nine months~~quarter of ~~2008~~2009 compared to the same period of ~~2007.~~2008. The following table presents changes from the prior year by expense category:

Expenses – Changes
Increase
(Decrease)

(In millions)
Purchased power costs $ 96
Other operating costs 35
Provision for depreciation 2
Amortization of regulatory assets (1 )
Deferral of new regulatory assets (18 )
General taxes 2
Net Increase in expenses $ 116

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

Purchased power costs increased by ~~$96~~$7 million in the first ~~nine months~~quarter of ~~2008~~2009, primarily due to higher composite unit prices ~~from non-affiliates in PJM. Other operating costs increased~~partially offset by ~~$35 million in the first nine months of 2008 primarily~~decreased KWH purchases due to ~~higher transmission expenses.~~

lower generation sales requirements. The deferral of new regulatory assets ~~increased~~decreased in the first ~~nine months~~quarter of ~~2008~~2009 primarily due to ~~increased~~decreased transmission cost deferrals ~~($29 million)~~reflecting lower PJM transmission service expenses and ~~universal service charge deferrals ($4 million), partially offset by~~ the ~~absence of the 2007 deferral of previously expensed decommissioning costs ($15 million) for the Saxton nuclear research facility (see Regulatory Matters).~~increased transmission revenues described above.

Other Expense

Other expense increased ~~$8 million~~ in the first ~~nine months~~quarter of ~~2008~~2009 primarily due to a decrease in interest ~~earned~~deferred on ~~stranded~~ regulatory assets, reflecting a lower regulatory asset ~~balances,~~base, and ~~reduced life insurance investment values, partially offset by lower~~an increase in interest ~~expense.~~expense from Met-Ed’s $300 million Senior Notes issuance in January 2009.

Legal Proceedings

New Accounting Standards and Interpretations

8573

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Metropolitan Edison Company:

We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its ~~subsidiaries~~subsidiary as of ~~September 30, 2008~~March 31, 2009 and the related consolidated statements of income, ~~and~~ comprehensive income and cash flows for each of the three-month ~~and nine-month~~ periods ended ~~September 30, 2008~~March 31, 2009 and ~~2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007.~~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, ~~2007,~~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 ~~28, 2008,~~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, ~~2007,~~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

~~November 6, 2008~~May 7, 2009

8674

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
(In thousands)

REVENUES:
Electric sales $ 434,742 $ 391,083 $ 1,188,171 $ 1,087,460
Gross receipts tax collections 20,793 19,524 59,669 55,146
Total revenues 455,535 410,607 1,247,840 1,142,606

EXPENSES:
Purchased power 245,699 209,842 680,424 584,249
Other operating costs 126,659 106,104 350,704 315,227
Provision for depreciation 11,394 11,154 33,446 31,969
Amortization of regulatory assets 34,642 36,853 101,383 101,965
Deferral of new regulatory assets (30,962 ) (19,151 ) (111,545 ) (93,772 )
General taxes 23,030 21,986 64,887 63,208
Total expenses 410,462 366,788 1,119,299 1,002,846

OPERATING INCOME 45,073 43,819 128,541 139,760

OTHER INCOME (EXPENSE):
Interest income 4,016 7,239 14,368 22,740
Miscellaneous income 88 1,366 568 3,973
Interest expense (11,014 ) (13,291 ) (33,666 ) (38,471 )
Capitalized interest 93 292 73 940
Total other expense (6,817 ) (4,394 ) (18,657 ) (10,818 )

INCOME BEFORE INCOME TAXES 38,256 39,425 109,884 128,942

INCOME TAXES 16,270 14,737 45,866 53,145

NET INCOME 21,986 24,688 64,018 75,797

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (2,233 ) (1,452 ) (6,699 ) (4,357 )
Unrealized gain on derivative hedges 84 83 252 251
Other comprehensive loss (2,149 ) (1,369 ) (6,447 ) (4,106 )
Income tax benefit related to other comprehensive loss (971 ) (693 ) (2,912 ) (2,078 )
Other comprehensive loss, net of tax (1,178 ) (676 ) (3,535 ) (2,028 )

TOTAL COMPREHENSIVE INCOME $ 20,808 $ 24,012 $ 60,483 $ 73,769

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 STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)

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

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

OPERATING INCOME		37,659			45,631

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

INCOME BEFORE INCOME TAXES		28,357			38,910

INCOME TAXES		11,735			16,675

NET INCOME		16,622			22,235

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

TOTAL COMPREHENSIVE INCOME	$	19,466		$	21,056

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

8775

METROPOLITAN EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2008 2007
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 129 $ 135
Receivables-
Customers (less accumulated provisions of $3,905,000 and $4,327,000
respectively, for uncollectible accounts) 149,363 142,872
Associated companies 22,060 27,693
Other 21,130 18,909
Notes receivable from associated companies 11,412 12,574
Prepaid taxes 19,626 14,615
Other 481 1,348
224,201 218,146
UTILITY PLANT:
In service 2,044,493 1,972,388
Less - Accumulated provision for depreciation 770,510 751,795
1,273,983 1,220,593
Construction work in progress 32,801 30,594
1,306,784 1,251,187
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts 256,366 286,831
Other 982 1,360
257,348 288,191
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 418,568 424,313
Regulatory assets 540,785 494,947
Pension assets 59,740 51,427
Other 30,714 36,411
1,049,807 1,007,098
$ 2,838,140 $ 2,764,622
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 28,500 $ -
Short-term borrowings-
Associated companies 65,286 185,327
Other 250,000 100,000
Accounts payable-
Associated companies 23,643 29,855
Other 63,656 66,694
Accrued taxes 2,483 16,020
Accrued interest 7,273 6,778
Other 30,858 27,393
471,699 432,067
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,500 shares outstanding 1,198,206 1,203,186
Accumulated other comprehensive loss (18,932 ) (15,397 )
Accumulated deficit (75,139 ) (139,157 )
Total common stockholder's equity 1,104,135 1,048,632
Long-term debt and other long-term obligations 513,721 542,130
1,617,856 1,590,762
NONCURRENT LIABILITIES:
Accumulated deferred income taxes 455,898 438,890
Accumulated deferred investment tax credits 7,922 8,390
Nuclear fuel disposal costs 44,205 43,462
Asset retirement obligations 168,367 160,726
Retirement benefits 5,252 8,681
Other 66,941 81,644
748,585 741,793
COMMITMENTS AND CONTINGENCIES (Note 11)
$ 2,838,140 $ 2,764,622

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

METROPOLITAN EDISON COMPANY

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

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

8876

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)

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

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

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

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

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

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months
Ended September 30
2008 2007
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 64,018 $ 75,797
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 33,446 31,969
Amortization of regulatory assets 101,383 101,965
Deferred costs recoverable as regulatory assets (9,673 ) (53,276 )
Deferral of new regulatory assets (111,545 ) (93,772 )
Deferred income taxes and investment tax credits, net 39,919 20,514
Accrued compensation and retirement benefits (18,948 ) (14,404 )
Cash collateral - 1,650
Pension trust contribution - (11,012 )
Decrease (increase) in operating assets-
Receivables (19,751 ) (57,599 )
Prepayments and other current assets (4,144 ) 7,227
Increase (decrease) in operating liabilities-
Accounts payable (9,250 ) (79,316 )
Accrued taxes (13,285 ) 3,024
Accrued interest 495 (153 )
Other 13,510 11,386
Net cash provided from (used for) operating activities 66,175 (56,000 )

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 28,500 -
Short-term borrowings, net 29,959 193,324
Redemptions and Repayments-
Long-term debt (28,640 ) (50,000 )
Net cash provided from financing activities 29,819 143,324

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (87,536 ) (74,812 )
Sales of investment securities held in trusts 131,915 153,943
Purchases of investment securities held in trusts (140,429 ) (162,573 )
Loans from (to) associated companies, net 1,163 (3,511 )
Other (1,113 ) (375 )
Net cash used for investing activities (96,000 ) (87,328 )

Net decrease in cash and cash equivalents (6 ) (4 )
Cash and cash equivalents at beginning of period 135 130
Cash and cash equivalents at end of period $ 129 $ 126

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

8977

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 ~~$62~~$19 million in the first ~~nine months~~quarter of ~~2008,~~2009, compared to ~~$74~~$21 million in the same period of ~~2007.~~2008. The decrease was primarily due to ~~increased purchased power costs, net amortization of regulatory assets, interest expense and other operating costs,~~lower revenues, partially offset by ~~higher revenues.~~an increase in the deferral of new regulatory assets.

Revenues

Revenues ~~increased~~decreased by ~~$96~~$7 million, or ~~9.2%~~1.7%, in the first ~~nine months~~quarter of 2008 primarily due to higher retail and wholesale generation revenues, distribution throughput revenues and PJM transmission revenues. Wholesale revenues increased $76 million in the first nine months of 2008,2009 as compared to the same period of ~~2007,~~2008, primarily due to lower retail generation revenues and PJM transmission revenues, partially offset by increased distribution throughput revenues and wholesale generation revenues. Wholesale generation revenues increased $7 million in the first quarter of 2009 as compared to the same period of 2008, primarily reflecting higher ~~spot market prices for~~ PJM ~~market participants.~~capacity prices.

In the first ~~nine months~~quarter of ~~2008,~~2009, retail generation revenues ~~increased $3~~decreased $8 million primarily due to ~~higher composite unit prices in all customer classes and higher~~lower KWH sales to the commercial ~~customers,~~and industrial customer classes due to weakened economic conditions, partially offset by a slight ~~decrease~~increase in KWH sales to ~~industrial customers.~~the residential customer class.

Changes in retail generation sales and revenues in the first ~~nine months~~quarter of ~~2008~~2009 compared to the same period of ~~2007~~2008 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)

Residential		-0.4	%
Commercial		~~0.7~~(3.2	) %
Industrial		(~~0.3~~13.9	) %
Net ~~Increase~~Decrease in Retail Generation Sales		~~0.2~~(4.9	) %

Retail Generation Revenues Increase
(In millions)
Residential $ 1
Commercial 2
Industrial -
Increase in Retail Generation Revenues $ 3

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

Revenues from distribution throughput increased $7$5 million in the first ~~nine months~~quarter of ~~2008~~2009 compared to the same period of ~~2007. Higher usage in the commercial and industrial sectors along with~~2008, primarily due to an increase in transmission rates, resulting from the annual update of Penelec’s TSC rider effective June 1, 2008, ~~(see Regulatory Matters),~~and a slight increase in usage in the residential sector. Partially offsetting this increase was ~~partially offset by a decrease~~lower usage in ~~distribution rates.~~the commercial and industrial sectors, reflecting economic conditions in Penelec’s service territory.

Changes in distribution KWH deliveries and revenues in the first ~~nine months~~quarter of ~~2008~~2009 compared to the same period of ~~2007~~2008 are summarized in the following tables:

Distribution KWH Deliveries	Increase (Decrease)

Residential		-0.4	%
Commercial		~~0.7~~(3.2	) %
Industrial		~~1.7~~(12.0	) %
~~Increase~~Net Decrease in Distribution Deliveries		~~0.8~~(4.6	) %

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

Distribution Revenues
Increase
(Decrease)

(In millions)

Residential $ 6
Commercial 2
Industrial (1 )
Net Increase in Distribution Revenues $ 7

PJM transmission revenues ~~increased~~decreased by ~~$12~~$13 million in the first ~~nine months~~quarter of ~~2008~~2009 compared to the same period of ~~2007,~~2008, primarily due to ~~higher PJM FTR revenue.~~lower revenues related to Penelec’s Financial Transmission Rights. Penelec defers the difference between transmission revenues and ~~net~~ transmission costs incurred, ~~in PJM,~~ resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses increased by ~~$105~~$5 million in the first ~~nine months~~quarter of ~~2008~~2009 as compared with the same period of ~~2007.~~2008. The following table presents changes from the prior year by expense category:

Expenses - Changes Increase
(In millions)
Purchased power costs $ 69
Other operating costs 6
Provision for depreciation 4
Amortization of regulatory assets, net 23
General taxes 3
Increase in expenses $ 105

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

Purchased power costs increased by ~~$69~~$2 million, or ~~11.7%~~0.9%, in the first ~~nine months~~quarter of ~~2008~~2009 compared to the same period of ~~2007,~~2008, primarily due ~~primarily~~ to ~~higher~~increased composite unit prices, ~~from non-affiliates in the PJM market.~~partially offset by reduced volume as a result of lower KWH sales requirements. Other operating costs increased by $6 million in the first ~~nine months~~quarter of ~~2008, principally~~2009 primarily due to higher ~~transmission expenses and higher expenses related to Penelec’s customer assistance programs.~~employee benefit expenses. Depreciation expense increased $2 million in the first quarter of 2009 primarily due to an increase in depreciable property in service since the ~~third~~first quarter of ~~2007.~~

~~Amortization~~2008. The deferral of new regulatory assets ~~(net of deferrals)~~ increased $4 million in the first ~~nine months~~quarter of ~~2008~~2009 primarily due to ~~the absence of the 2007 deferral of previously expensed decommissioning costs ($12 million) for the Saxton nuclear research facility (see Regulatory Matters) and decreased~~an increase in transmission cost deferrals ~~($16 million), partially offset by an increase in universal service charge deferrals ($5 million).~~

~~In the first nine months~~as a result of ~~2008, general taxes~~ increased ~~from the same period of 2007, due to higher gross receipts taxes ($4 million), partially offset by lower capital stock taxes ($1 million).~~net congestion costs.

Other ~~Expense~~Income

In the first ~~nine months~~quarter of ~~2008,~~2009, other ~~expense~~income increased primarily due to ~~higher~~lower interest expense ~~associated with Penelec’s $300 million senior note issuance in August 2007 and~~on reduced ~~life insurance investment values.~~borrowings from the regulated money pool.

Legal Proceedings

New Accounting Standards and Interpretations

9179

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Pennsylvania Electric Company:

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of ~~September 30, 2008~~March 31, 2009 and the related consolidated statements of income, ~~and~~ comprehensive income and cash flows for each of the three-month ~~and nine-month~~ periods ended ~~September 30, 2008~~March 31, 2009 and ~~2007 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2008 and 2007.~~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, ~~2007,~~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 ~~28, 2008,~~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, ~~2007,~~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

~~November 6, 2008~~May 7, 2009

9280

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
(In thousands)
REVENUES:
Electric sales $ 372,576 $ 336,798 $ 1,083,986 $ 991,769
Gross receipts tax collections 17,200 16,637 52,704 48,989
Total revenues 389,776 353,435 1,136,690 1,040,758

EXPENSES:
Purchased power 230,656 203,247 657,681 588,583
Other operating costs 54,727 51,571 175,904 169,299
Provision for depreciation 14,097 12,566 40,531 36,678
Amortization of regulatory assets, net 23,415 20,861 55,346 32,648
General taxes 20,285 19,433 60,485 57,634
Total expenses 343,180 307,678 989,947 884,842

OPERATING INCOME 46,596 45,757 146,743 155,916

OTHER INCOME (EXPENSE):
Miscellaneous income (expense) (93 ) 1,483 774 5,035
Interest expense (14,934 ) (14,017 ) (45,157 ) (38,426 )
Capitalized interest 57 194 (679 ) 737
Total other expense (14,970 ) (12,340 ) (45,062 ) (32,654 )

INCOME BEFORE INCOME TAXES 31,626 33,417 101,681 123,262

INCOME TAXES 9,058 10,387 39,324 49,025

NET INCOME 22,568 23,030 62,357 74,237

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (3,474 ) (2,825 ) (10,421 ) (8,475 )
Unrealized gain on derivative hedges 16 16 48 49
Change in unrealized gain on available-for-sale securities 2 10 (8 ) (6 )
Other comprehensive loss (3,456 ) (2,799 ) (10,381 ) (8,432 )
Income tax benefit related to other comprehensive loss (1,510 ) (1,294 ) (4,536 ) (3,894 )
Other comprehensive loss, net of tax (1,946 ) (1,505 ) (5,845 ) (4,538 )

TOTAL COMPREHENSIVE INCOME $ 20,622 $ 21,525 $ 56,512 $ 69,699

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 STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)

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

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

OPERATING INCOME		44,225			55,990

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

INCOME BEFORE INCOME TAXES		31,812			39,671

INCOME TAXES		13,122			18,279

NET INCOME		18,690			21,392

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

TOTAL COMPREHENSIVE INCOME	$	20,584		$	19,452

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

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	13		$	23
Receivables-
Customers (less accumulated provisions of $3,285,000 and $3,121,000,
respectively, for uncollectible accounts)		140,783			146,831
Associated companies		80,387			65,610
Other		19,493			26,766
Notes receivable from associated companies		15,198			14,833
Prepaid taxes		66,392			16,310
Other		1,142			1,517
		323,408			271,890
UTILITY PLANT:
In service		2,345,475			2,324,879
Less - Accumulated provision for depreciation		873,677			868,639
		1,471,798			1,456,240
Construction work in progress		25,042			25,146
		1,496,840			1,481,386
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		113,265			115,292
Non-utility generation trusts		117,899			116,687
Other		289			293
		231,453			232,272
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		768,628			768,628
Power purchase contract asset		78,226			119,748
Other		15,308			18,658
		862,162			907,034
	$	2,913,863		$	2,892,582
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	145,000		$	145,000
Short-term borrowings-
Associated companies		112,034			31,402
Other		250,000			250,000
Accounts payable-
Associated companies		49,981			63,692
Other		42,004			48,633
Accrued taxes		4,053			13,264
Accrued interest		13,730			13,131
Other		26,591			31,730
		643,393			596,852
CAPITALIZATION:
Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
4,427,577 shares outstanding		88,552			88,552
Other paid-in capital		912,380			912,441
Accumulated other comprehensive loss		(126,103	)		(127,997	)
Retained earnings		94,803			76,113
Total common stockholder's equity		969,632			949,109
Long-term debt and other long-term obligations		633,355			633,132
		1,602,987			1,582,241
NONCURRENT LIABILITIES:
Regulatory liabilities		48,847			136,579
Accumulated deferred income taxes		183,906			169,807
Retirement benefits		172,544			172,718
Asset retirement obligations		87,395			87,089
Power purchase contract liability		112,462			83,600
Other		62,329			63,696
		667,483			713,489
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	2,913,863		$	2,892,582

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

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31
	2009			2008
	(In thousands)

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

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

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

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

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

9383

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2008 2007
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 36 $ 46
Receivables-
Customers (less accumulated provisions of $3,240,000 and $3,905,000
respectively, for uncollectible accounts) 130,427 137,455
Associated companies 57,715 22,014
Other 20,367 19,529
Notes receivable from associated companies 15,406 16,313
Prepaid taxes 31,313 1,796
Other 494 1,281
255,758 198,434
UTILITY PLANT:
In service 2,290,777 2,219,002
Less - Accumulated provision for depreciation 858,150 838,621
1,432,627 1,380,381
Construction work in progress 29,503 24,251
1,462,130 1,404,632
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts 128,594 137,859
Non-utility generation trusts 115,938 112,670
Other 299 531
244,831 251,060
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 771,085 777,904
Pension assets 75,992 66,111
Other 29,610 33,893
876,687 877,908
$ 2,839,406 $ 2,732,034
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 145,000 $ -
Short-term borrowings-
Associated companies 30,483 214,893
Other 250,000 -
Accounts payable-
Associated companies 83,058 83,359
Other 47,796 51,777
Accrued taxes 3,923 15,111
Accrued interest 14,034 13,167
Other 30,297 25,311
604,591 403,618
CAPITALIZATION:
Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
4,427,577 shares outstanding 88,552 88,552
Other paid-in capital 914,863 920,616
Accumulated other comprehensive income (loss) (899 ) 4,946
Retained earnings 50,300 57,943
Total common stockholder's equity 1,052,816 1,072,057
Long-term debt and other long-term obligations 632,910 777,243
1,685,726 1,849,300
NONCURRENT LIABILITIES:
Regulatory liabilities 104,927 73,559
Asset retirement obligations 85,748 81,849
Accumulated deferred income taxes 253,798 210,776
Retirement benefits 40,864 41,298
Other 63,752 71,634
549,089 479,116
COMMITMENTS AND CONTINGENCIES (Note 11)
$ 2,839,406 $ 2,732,034

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 STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months
Ended September 30
2008 2007
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 62,357 $ 74,237
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 40,531 36,678
Amortization of regulatory assets, net 55,346 32,648
Deferred costs recoverable as regulatory assets (20,304 ) (54,228 )
Deferred income taxes and investment tax credits, net 68,377 8,065
Accrued compensation and retirement benefits (21,190 ) (16,032 )
Cash collateral - 50
Pension trust contribution - (13,436 )
Decrease (increase) in operating assets-
Receivables (42,971 ) 13,809
Prepayments and other current assets (28,730 ) (4,757 )
Increase (decrease) in operating liabilities-
Accounts payable (3,437 ) 14,299
Accrued taxes (11,521 ) (4,930 )
Accrued interest 867 6,608
Other 14,663 9,197
Net cash provided from operating activities 113,988 102,208

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 45,000 297,149
Short-term borrowings, net 65,590 53,082
Redemptions and Repayments-
Long-term debt (45,332 ) -
Common stock - (200,000 )
Dividend Payments-
Common stock (70,000 ) (125,000 )
Net cash provided from (used for) financing activities (4,742 ) 25,231

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (94,810 ) (70,076 )
Loan repayments from associated companies, net 907 2,378
Sales of investment securities held in trust 84,499 94,292
Purchases of investment securities held in trust (96,950 ) (150,711 )
Other (2,902 ) (3,328 )
Net cash used for investing activities (109,256 ) (127,445 )

Net decrease in cash and cash equivalents (10 ) (6 )
Cash and cash equivalents at beginning of period 46 44
Cash and cash equivalents at end of period $ 36 $ 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 ~~2007~~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 ~~certain costs~~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 $130 million as of ~~September 30, 2008 were $64~~March 31, 2009 (JCP&L - $54 million ~~for JCP&L~~ and ~~$64 million for Met-Ed.~~Met-Ed - $76 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed. The following table discloses regulatory assets by company:

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

Penelec had net regulatory liabilities of approximately ~~$105~~$49 million

and ~~$74~~$137 million as of ~~September 30, 2008~~March 31, 2009 and December 31, ~~2007,~~ 2008,

respectively. These net regulatory liabilities are included in Other

Non-current Liabilities on the Consolidated Balance Sheets.

9684

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

On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007 the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 million (OE - $92 million, CEI - $69 million and TE - $28 million). In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million (OE - $114 million, CEI - $79 million and TE - $33 million) of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the deferred fuel costs is addressed in the Ohio Companies’ comprehensive ESP filing, as described below. If the recovery of the deferred fuel costs is not resolved in the ESP, or in the event the MRO is implemented, recovery of the deferred fuel costs will be resolved in the proceeding that was instituted with the PUCO on February 8, 2008, as referenced above.

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 (OE - $156 million, CEI - $108 million and TE - $68 million).~~million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. ~~In its reports,~~On January 21, 2009, the PUCO ~~Staff recommended a~~granted the Ohio Companies’ application to increase electric distribution ~~rate increase in the range of $161 million to $180~~rates by $136.6 million (OE - ~~$57 million to $66~~$68.9 million, CEI - ~~$54 million to $61~~$29.2 million and TE - ~~$50 million to $53~~$38.5 million)~~, with $108 million to $127 million~~. These increases went into effect for ~~distribution revenue increases~~OE and ~~$53 million for recovery of costs deferred under prior cases. Evidentiary hearings began~~TE on January ~~29, 2008~~23, 2009, and ~~continued through February 25, 2008. During~~will go into effect for CEI on May 1, 2009. Applications for rehearing of this order were filed by the ~~evidentiary hearings~~Ohio Companies and ~~filing of briefs, the PUCO Staff decreased their recommended revenue increase to a range of $117 million to $135 million. Additionally, in testimony submitted~~one other party on February ~~11, 2008, the~~20, 2009. The PUCO ~~Staff adopted a position regarding interest deferred~~granted these applications for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $58 million (OE - $38 million, CEI - $13 million and TE - $7 million) of interest costs deferred through September 30, 2008. The Ohio Companies’ electric distribution rate request is addressed in their comprehensive ESP filing, as described below.rehearing on March 18, 2009.

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

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

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

a phase-in of new generation rates for up to a three-year period, whereby customers would receive a 10% phase-in credit; related costs (expected to approximate $429 million (OE - $198 million, CEI - $150 million and TE - $81 million) in 2009, $488 million (OE - $226 million, CEI - $170 million and TE - $92 million) in 2010 and $553 million (OE - $257 million, CEI - $193 million and TE - $103 million) in 2011) would be deferred for future collection over a period not to exceed 10 years;

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

9785

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

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

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

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

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

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

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

Major provisions of the legislation include:

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

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

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

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

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

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

~~The current legislative session ends on November 30, 2008, and any pending legislation~~

Legislation addressing rate mitigation and the expiration of rate caps was not enacted ~~by that time must be re-introduced~~ in ~~order to be considered~~2008; however, several bills addressing these issues have been introduced in the ~~next~~current legislative session, which ~~begins~~began in January 2009. ~~While the~~The final form and impact of such legislation is ~~uncertain, several legislators and the Governor have indicated their intent to address these issues next year.~~

uncertain.

New Jersey (Applicable to JCP&L)

~~100~~

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

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. AFollowing public hearing ~~on these proposed rules was held on April 23, 2008~~ and consideration of comments from interested parties, ~~were submitted by May 19, 2008.~~the NJBPU approved final regulations effective April 6, 2009. These regulations are not expected to materially impact JCP&L.

~~On April 17, 2008, a draft EMP was released for public comment.~~

The ~~final~~ EMP was issued on October 22, 2008, ~~and establishes~~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.

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

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

Transmission Service between MISO and PJM

~~101~~

On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.

PJM Transmission Rate ~~Design~~

Post Transition Period Rate Design

~~102~~

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

~~Interconnection Agreement with AMP-Ohio~~

Duquesne’s Request to Withdraw from PJM

~~103~~89

~~Several issues surrounding Duquesne’s transition into MISO continue to be contested at the FERC. Specifically, Duquesne’s obligation to pay~~Changes ordered for ~~transmission expansion costs allocated to the Duquesne zone when they were a member of~~ PJM and other issues in which market participants wish to be held harmless by Duquesne’s transition. FirstEnergy filed for rehearing on these issues on October 3, 2008. Duquesne’s transition into MISO is also contingent upon the start of MISO’s ancillary services market and consolidation of its balancing authorities, currently scheduled for January 6, 2009.

~~Complaint against PJM RPM~~Reliability Pricing Model (RPM) Auction

MISO Resource Adequacy Proposal

~~Organized Wholesale Power Markets~~

~~104~~

FES Sales to Affiliates

Environmental Matters

Various federal, state and local authorities regulate FES and the ~~Companies~~Utilities with regard to air and water quality and other environmental matters. The effects of compliance on FES and the ~~Companies~~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 estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.~~

FES and the ~~Companies~~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 ~~Companies’~~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)~~FES, OE, JCP&L, Met-Ed and Penelec)

FES is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to ~~$32,500~~$37,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FES believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

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

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

~~105~~

~~106~~

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.

National Ambient Air Quality Standards (Applicable to FES)

Mercury Emissions (Applicable to FES)

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

~~107~~

Climate Change (Applicable to FES)

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

Clean Water Act (Applicable to FES)

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April ~~14, 2008,~~1, 2009, the Supreme Court of the United States ~~granted a petition for a writ of certiorari to review~~reversed one significant aspect of the Second Circuit Court’s opinion ~~which is whether~~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. ~~Oral argument before the Supreme Court is scheduled for December 2, 2008.~~ FES is studying various control options and their costs and effectiveness. Depending on the results of such studies ~~the outcome of the Supreme Court’s review of the Second Circuit’s decision,~~and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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

~~108~~94

The Utilities have been named as ~~PRPs~~potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all ~~PRPs~~potentially responsible parties for a particular site may be liable on a joint and several basis. ~~Therefore, environmental~~Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of ~~September 30, 2008,~~March 31, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately ~~$94~~$91 million (JCP&L - ~~$68~~- $64 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - ~~$24~~$25 million) have been accrued through ~~September 30, 2008.~~March 31, 2009. Included in the total ~~for JCP&L~~ are accrued liabilities of approximately ~~$57~~$56 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

Other Legal Proceedings

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

~~In August 2002,~~After various motions, rulings and appeals, the ~~trial Court granted partial summary judgment to JCP&L and dismissed the plaintiffs'~~Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, ~~and~~ strict product ~~liability. In November 2003,~~liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial ~~Court granted JCP&L's motion to decertify~~court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limitedonly to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation ~~resulting~~which resulted in planned and unplanned outages in the area during a 2-3 day ~~period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages~~period, and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which,(2) in March 2007, ~~reversed~~ the ~~decertification of the Red Bank class and~~Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. ~~JCP&L filed a petition for allowance of an appeal of~~Proceedings then continued at the ~~Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court~~trial court level and a case management conference with the presiding Judge was held on June 13, 2008. At that conference, counsel for the ~~plaintiffs~~Plaintiffs stated ~~their~~his intent to drop ~~their~~his efforts to create a class-wide damage model and, instead of dismissing the class action, expressed ~~their~~his desire for a bifurcated trial on liability and damages. The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario. Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure.In response, JCP&L ~~has received~~filed an objection to the plaintiffs’ proposed ~~plan of action, and intends to file its objection to the proposed~~trial plan and ~~also file a renewed~~another motion to decertify the class. On March 31, 2009, the trial court granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed their appeal to the trial court's decision to decertify the class.

On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation requires JCP&L to respond to NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. JCP&L is ~~defending~~not able at this ~~action but is unable~~time to predict ~~the outcome. No liability has been accrued as~~what actions, if any, that NERC will take upon receipt of ~~September 30, 2008.~~JCP&L’s response to NERC’s data request.

~~109~~95

Nuclear Plant Matters~~(Applicable~~ (Applicable to FES)

Other Legal Matters (Applicable to ~~OE, JCP&L~~FES and ~~FES)~~each of the Utilities)

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

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

FES and the Utilities accrue legal liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FES and the Utilities have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on their financial condition, results of operations and cash flows.

~~110~~96

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

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

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

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

~~SFAS 161~~FSP FAS 115-2 and FAS 124-2 - ~~“Disclosures about Derivative Instruments~~“Recognition and ~~Hedging Activities – an Amendment~~Presentation of ~~FASB Statement No. 133”~~Other-Than-Temporary Impairments”

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

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

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

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

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

Recent Developments (Applicable to ~~increase its disclosure requirements for derivative instruments~~FES and ~~hedging activities.~~each of the Utilities to the extent indicated)

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

~~111~~97

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

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

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

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, ~~2007~~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 9)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 ~~September 30, 2008~~March 31, 2009, and for the three-month ~~and nine-month~~ periods ended ~~September 30,~~March 31, 2009 and 2008, ~~and 2007,~~ have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated ~~November 6, 2008)~~May 7, 2009) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.

2. EARNINGS PER SHARE

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. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an accelerated share repurchase program at an initial price of approximately $900 million. A final purchase price adjustment of $51 million was settled in cash on December 13, 2007. The following table reconciles basic and diluted earnings per share of common stock:

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

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

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

~~112~~98

Three Months Nine Months

Ended September 30

Ended September 30

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

Net income $ 471 $ 413 $ 1,010 $ 1,041

Average shares of common stock outstanding – Basic 304 304 304 307
Assumed exercise of dilutive stock options and awards 3 3 3 4
Average shares of common stock outstanding – Dilutive 307 307 307 311

Basic earnings per share $ 1.55 $ 1.36 $ 3.32 $ 3.39
Diluted earnings per share $ 1.54 $ 1.34 $ 3.29 $ 3.35

3. ~~GOODWILL~~

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and more frequently as indicators of impairment arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment is indicated, FirstEnergy recognizes a loss – calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill.

FirstEnergy's 2008 annual review was completed in the third quarter of 2008 with no impairment indicated. As discussed in Note 12(B), the Ohio Companies filed a comprehensive ESP and MRO with the PUCO on July 31, 2008. The annual goodwill impairment analysis assumed management's best estimate of the outcome of those filings. There was no impairment indicated for FirstEnergy and the Ohio Companies based on a probability-weighted outcome of the ESP and MRO proceedings. If the PUCO’s final decision authorizes less revenue recovery than the amounts assumed, an additional impairment analysis would be performed at that time that could result in future goodwill impairment.

FirstEnergy's goodwill primarily relates to its energy delivery services segment. In the first and third quarters of 2008, FirstEnergy adjusted goodwill by $1 million and $23 million, respectively, of the former GPU companies due to the realization of tax benefits that had been reserved under purchase accounting. The following tables reconcile changes to goodwill for the three months and nine months ended September 30, 2008.

Three Months Ended

FirstEnergy

FES

CEI

TE

JCP&L

Met-Ed

Penelec

(In millions)
Balance as of July 1, 2008

$
5,606

$
24

$
1,689

$
501

$
1,826

$
424

$
778

Adjustments related to GPU acquisition

(23
)
-
-

-

(11
)

(5
)

(7
)
Balance as of September 30, 2008

$
5,583

$
24

$
1,689

$
501

$
1,815

$
419

$
771

Nine Months Ended

FirstEnergy

FES

CEI

TE

JCP&L

Met-Ed

Penelec

(In millions)

Balance as of January 1, 2008

$
5,607

$
24

$
1,689

$
501

$
1,826

$
425

$
778

Adjustments related to GPU acquisition

(24
)
-
-

-

(11
)

(6
)

(7
)
Balance as of September 30, 2008

$
5,583

$
24

$
1,689

$
501

$
1,815

$
419

$
771

~~4. DIVESTITURES AND DISCONTINUED OPERATIONS~~

On March 7, 2008, FirstEnergy sold certain telecommunication assets, resulting in a net after-tax gain of $19.3 million. The sale of assets did not meet the criteria for classification as discontinued operations as of September 30, 2008.

5. FAIR VALUE MEASURES

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

~~113~~

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

~~Level 1 – Quoted prices are available~~disclosed in ~~active markets for identical assets or liabilities as~~Note 5 of the ~~reporting date. Active markets are those where transactions for the asset or liability occur~~Notes to Consolidated Financial Statements 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, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Instruments in this category include non-exchange-traded derivatives such as forwards and certain interest rate swaps.

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

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

The following table sets forth FirstEnergy’s financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of ~~September 30,~~March 31, 2009 and December 31, 2008. ~~As required by SFAS 157, assets~~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 ~~fair value~~ assets and liabilities and their placement within the fair value hierarchy levels.

September 30, 2008
Recurring Fair Value Measures Level 1 Level 2 Level 3 Total
(In millions)
Assets:
    Derivatives $ - $ 45 $ - $ 45
    Nuclear decommissioning trusts 761 1,112 - 1,873
    Other investments 19 312 - 331
    Total $ 780 $ 1,469 $ - $ 2,249

Liabilities:
    Derivatives $ 8 $ 19 $ - $ 27
    NUG contracts(1)
- - 603 603
    Total $ 8 $ 19 $ 603 $ 630

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

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

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

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

~~114~~

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

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

(1)

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

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

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

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

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

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

The following ~~tables provide~~table sets forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three ~~and nine~~ months ended ~~September 30, 2008:~~March 31, 2009 and 2008 (in millions):

Three Months Nine Months
(In millions)
Balance at beginning of period $ 644 $ 750
    Realized and unrealized gains (losses)(1)
(32 ) (120 )
    Purchases, sales, issuances and settlements, net(1)
(9 ) (27 )
    Net transfers to (from) Level 3 - -
Balance as of September 30, 2008 $ 603 $ 603

Change in unrealized gains (losses) relating to
    instruments held as of September 30, 2008 $ (32 ) $ (120 )

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

~~Under FSP FAS 157-2, “Effective Date of FASB Statement No. 157”, FirstEnergy deferred until~~

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

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

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

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

6.4. DERIVATIVE INSTRUMENTS

FirstEnergy is exposed to financial risks resulting from ~~the fluctuation of~~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 ~~principally~~ for ~~hedging~~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 inon its Consolidated Balance Sheet at their fair value unless they meet the ~~criteria for the~~ normal ~~purchases~~purchase and normal sales ~~exception.~~criteria. Derivatives that meet those criteria are accounted for at cost. ~~FirstEnergy regularly assesses derivatives based on the normal purchases and normal sales criteria and expects no changes in eligibility for the normal purchases and normal sales exception.~~ The changes in the fair value of derivative instruments that do not meet the normal ~~purchases~~purchase and normal sales ~~exception~~criteria are recorded as other expense, as AOCL, or as part of the value of the hedged item ~~depending~~as described below.

Interest Rate Derivatives

Under the revolving credit facility, FirstEnergy incurs variable interest charges based on ~~whether or not it is designated~~LIBOR. In 2008, FirstEnergy entered into swaps with a notional value of $200 million to hedge against changes in associated interest rates. Hedges with a notional value of $100 million expire in November 2009 and the remainder expire in November 2010. The swaps are accounted for as ~~part~~cash flow hedges under SFAS 133. As of ~~a hedge transaction,~~March 31, 2009, the ~~nature of the hedge transaction and hedge effectiveness. FirstEnergy does not offset~~ fair value ~~for the right to reclaim collateral or the obligation to return collateral.~~of outstanding swaps was $(4) million.

FirstEnergy ~~hedges anticipated transactions using~~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. Such transactions~~hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first quarter of 2009, FirstEnergy terminated forward swaps with a notional value of $100 million when a subsidiary issued long term debt. The gain associated with the termination was $1.3 million, of which $0.3 million was ineffective and recognized as an adjustment to interest expense. The remaining effective portion will be amortized to interest expense over the life of the hedged debt. FirstEnergy currently has no outstanding forward swaps.

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

100

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

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

Commodity Derivatives

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

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

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


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

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

~~115~~101

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

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

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


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

(1) The ineffective portion was immaterial.

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

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

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

Total unamortized losses ~~of $64 million~~ included in AOCL associated with commodity derivatives were $32 million ($19 million net of tax) as of ~~September 30, 2008, for derivative hedging activity,~~March 31, 2009, as compared to ~~$75~~$44 million ($27 million net of tax) as of December 31, ~~2007,~~2008. The change (net of tax) resulted from a net $3$5 million increase related to current hedging activity and a ~~$14~~$13 million decrease due to net hedge losses reclassified to earnings during the ~~nine months ended September 30, 2008.~~first quarter of 2009. Based on current estimates, approximately ~~$16~~$15 million (after tax) of the net deferred losses on derivative instruments in AOCL as of ~~September 30, 2008~~March 31, 2009 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market ~~factors, including commodity prices, counterparty credit and interest rates.~~factors.

Many of FirstEnergy’s commodity derivatives contain credit risk features. As of March 31, 2009, FirstEnergy posted $141 million of collateral related to net liability positions and held no counterparties’ funds related to asset positions. The collateral FirstEnergy has ~~entered into swaps~~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 ~~have been designated as fair value hedges of fixed-rate, long-term~~would require FirstEnergy to post additional collateral if the credit rating for its debt ~~issues~~were to ~~protect against the risk of changes in the~~fall below investment grade. The aggregate fair value of ~~fixed-rate debt~~derivative instruments ~~due~~with credit-risk related contingent features that are in a liability position on March 31, 2009 was $4 million, for which no collateral has been posted. If FirstEnergy’s credit rating were to ~~lower interest rates. In order~~fall below investment grade, it would be required to ~~reduce counterparty exposure and lessen variable debt exposure under current market conditions, FirstEnergy unwound its remaining interest rate swaps. During the first nine months~~post $4 million of 2008, FirstEnergy received $3 million to terminate interest rate swaps with an aggregate notional value of $250 million. As of September 30, 2008, FirstEnergy has no outstanding interest rate swaps hedging fixed-rate long term debt.

During 2007 and the first nine months of 2008, FirstEnergy entered into several forward-starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated issuance of variable-rate short-term debt and fixed-rate long-term debt securities, by one or more of its subsidiaries, as outstanding debt matures during 2008 and 2009. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury and LIBOR rates between the date of hedge inception and the date of the debt issuance. FirstEnergy considers counterparty credit and nonperformance risk in its hedge assessments and continues to expect the forward-starting swaps to be effective in protecting against the risk of changes in future interest payments. During the first nine months of 2008, FirstEnergy terminated swaps with a notional value of $750 million and entered into swaps with a notional value of $950 million. FirstEnergy paid $16 millionadditional collateral related to the terminations, $5 million of which was deemed ineffective and recognized in current period earnings. FirstEnergy will recognize the remaining loss over the life of the associated future debt. As of September 30, 2008, FirstEnergy had forward swaps with an aggregate notional amount of $600 million and a fair value of $(0.2) million.

~~7. ASSET RETIREMENT OBLIGATIONS~~

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

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

FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of September 30, 2008, the fair value of the decommissioning trust assets was approximately $1.9 billion.

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

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

(In millions)

Balance, July 1, 2008

$
1,307

$
836

$
96

$
2

$
29

$
92

$
166

$
84

Liabilities incurred

5

-

-

-

-

-

-

-

Liabilities settled

(1
)
(1
)
-

-

-

-

-

-

Accretion

21

14

1

-

1

2

2

2

Revisions in estimated cash flows

(18
)
-

(18
)
-

-

-

-

-

Balance, September 30, 2008

$
1,314

$
849

$
79

$
2

$
30

$
94

$
168

$
86

Balance, July 1, 2007

$
1,228
$
784
$
91
$
2
$
27
$
87
$
156
$
79

Liabilities incurred

-

-

-

-

-

-

-

-

Liabilities settled

-

-

-

-

-

-

-

-

Accretion

19

13

1

-

1

1

2

2

Revisions in estimated cash flows

-

-

-

-

-

-

-

-

Balance, September 30, 2007

$
1,247
$
797
$
92
$
2
$
28
$
88
$
158
$
81

commodity derivatives.

~~116~~102

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

(In millions)

Balance, January 1, 2008

$
1,267

$
810

$
94

$
2

$
28

$
90

$
161

$
82

Liabilities incurred

5

-

-

-

-

-

-

-

Liabilities settled

(2
)
(1
)
(1
)
-

-

-

-

-

Accretion

62

40

4

-

2

4

7

4

Revisions in estimated cash flows

(18
)
-

(18
)
-

-

-

-

-

Balance, September 30, 2008

$
1,314
$
849
$
79
$
2
$
30
$
94
$
168
$
86

Balance, January 1, 2007

$
1,190

$
760

$
88

$
2

$
27

$
84

$
151

$
77

Liabilities incurred

-

-

-

-

-

-

-

-

Liabilities settled

(2
)
(1
)
-

-

-

-

-

-

Accretion

59

38

4

-

1

4

7

4

Revisions in estimated cash flows

-

-

-

-

-

-

-

-

Balance, September 30, 2007

$
1,247
$
797
$
92
$
2
$
28
$
88
$
158
$
81

8.5. PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its ~~subsidiaries’~~employees and non-qualified pension plans that cover certain employees. The ~~trusteed~~ plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December ~~31, 2007.~~31. FirstEnergy also provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

For the three months ended March 31, 2009 and 2008, FirstEnergy’s net pension and OPEB expense (benefit) was $43 million and $(15) million, respectively. The components of FirstEnergy's net ~~periodic~~ pension ~~cost~~ and other postretirement benefit cost (including amounts capitalized) for the three months ended March 31, 2009 and ~~nine months ended September 30,~~ 2008, ~~and 2007,~~ consisted of the following:

Three Months Nine Months
Ended September 30 Ended September 30
Pension Benefits 2008 2007 2008 2007
(In millions)
Service cost $ 21 $ 21 $ 62 $ 63
Interest cost 72 71 217 213
Expected return on plan assets (116 ) (112 ) (347 ) (337 )
Amortization of prior service cost 3 2 7 7
Recognized net actuarial loss 1 10 4 31
Net periodic cost (credit) $ (19 ) $ (8 ) $ (57 ) $ (23 )

	Three Months						Nine Months						Pension Benefits						Other Postretirement Benefits
	Ended September 30						Ended September 30						2009			2008			2009			2008
Other Postretirement Benefits	2008			2007			2008			2007
	(In millions)												(In millions)
Service cost	$	5		$	5		$	14		$	16		$	22		$	22		$	5		$	5
Interest cost		18			17			55			52			80			75			20			18
Expected return on plan assets		(13	)		(12	)		(38	)		(38	)		(81	)		(116	)		(9	)		(13	)
Amortization of prior service cost		(37	)		(37	)		(111	)		(112	)		3			3			(38	)		(37	)
Recognized net actuarial loss		12			11			35			34			42			2			16			12
Net periodic cost (credit)	$	(15	)	$	(16	)	$	(45	)	$	(48	)	$	66		$	(14	)	$	(6	)	$	(15	)

Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. ~~FES and the Utilities~~The Companies capitalize employee benefits related to construction projects. The net ~~periodic~~ pension ~~costs~~ and ~~net periodic~~other postretirement benefit costs (including amounts capitalized) recognized by ~~FES and~~ each of the ~~Utilities~~Companies for the three months ended March 31, 2009 and ~~nine months ended September 30,~~ 2008 ~~and 2007~~ were as follows:

~~117~~

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

Three Months Nine Months
Ended September 30 Ended September 30
Pension Benefit Cost (Credit) 2008 2007 2008 2007
(In millions)
FES $ 4 $ 5 $ 11 $ 16
OE (6 ) (4 ) (20 ) (12 )
CEI (1 ) - (3 ) 1
TE (1 ) - (2 ) -
JCP&L (4 ) (2 ) (11 ) (7 )
Met-Ed (3 ) (2 ) (8 ) (5 )
Penelec (3 ) (2 ) (10 ) (8 )
Other FirstEnergy subsidiaries (5 ) (3 ) (14 ) (8 )
$ (19 ) $ (8 ) $ (57 ) $ (23 )

Three Months Nine Months
Ended September 30 Ended September 30
Other Postretirement Benefit Cost (Credit) 2008 2007 2008 2007
(In millions)
FES $ (2 ) $ (2 ) $ (5 ) $ (7 )
OE (2 ) (3 ) (5 ) (8 )
CEI 1 1 2 3
TE 1 1 3 4
JCP&L (4 ) (4 ) (12 ) (12 )
Met-Ed (3 ) (3 ) (8 ) (8 )
Penelec (3 ) (3 ) (10 ) (10 )
Other FirstEnergy subsidiaries (3 ) (3 ) (10 ) (10 )
$ (15 ) $ (16 ) $ (45 ) $ (48 )

Under the Pension Protection Act of 2006, companies are generally required make a scheduled series of contributions to fund 100% of outstanding qualified pension benefit obligations over a seven year period. As of December 31, 2007, FirstEnergy’s pension plan was overfunded, and, therefore, FirstEnergy will not be required to make any contributions in 2009 for the 2008 plan year. However, the overall actual asset return as of December 31, 2008 may reduce the value of the pension plan’s assets to the level where contributions would be required in 2010 for the 2009 plan year.

9.6. VARIABLE INTEREST ENTITIES

FIN 46R addresses the consolidation of VIEs, including special-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the entity's residual economic risks and rewards. FirstEnergy and its subsidiaries consolidate ~~a VIE~~VIEs when they are determined to be the VIE's primary beneficiary as defined by FIN 46R. Effective January 1, 2009, FirstEnergy adopted SFAS 160. As a result, FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest within the Consolidated Balance Sheets is the result of earnings and losses of the noncontrolling interests and distributions to owners.

103

Mining Operations

On July 16, 2008, ~~FirstEnergy Ventures Corp., a subsidiary of FirstEnergy,~~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. ~~FirstEnergy~~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 ~~FirstEnergy Ventures Corp.~~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. ~~After~~In March 2009, FEV agreed to pay a total of $8.5 million (of which $1.7 million was paid in March 2009) to affiliates of the Boich Companies to purchase an additional 5% economic interest in the Signal Peak mining and coal transportation operations. Voting interests will remain unchanged after the sale is completed in July 2009. Effective January 16, 2010, the joint venture will have 18 months to exercise an option to acquire the remaining 20% stake in the mining operations. In accordance with FIN 46R, ~~FirstEnergy is including the limited liability companies created for~~FEV consolidates the mining and transportation operations of this joint venture in its ~~consolidated~~ financial statements.

Trusts

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

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.~~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.

~~118~~

Loss Contingencies

FES and the Ohio Companies are exposed to losses under their applicable ~~sale and leaseback~~sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments ~~are~~were made. The following table ~~shows~~discloses each company’s net exposure to loss based upon the casualty value provisions mentioned ~~above as of September 30, 2008:~~above:

Maximum Exposure
Discounted
Lease Payments, net
Net Exposure
(in millions)
FES $ 1,363 $ 1,209 $ 154
OE 788 597 191
CEI 718 79 639
TE 718 421 297

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

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

lease commitments is $1.7 billion

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

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. ~~Also in the second quarter of 2008,~~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, which purchases were undertaken in connection with the previously disclosed exercise of the periodic purchase option provided in the TE and CEI sale and leaseback arrangements.~~2. The Ohio Companies continue to lease these MW under ~~the~~their respective sale and leaseback arrangements and the related lease debt remains outstanding.

104

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~~Companies and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains ~~approximately 30~~24 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

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

Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it may incur for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs from these entities during the three months ended March 31, 2009 and ~~nine months ended September 30,~~ 2008 ~~and 2007~~ are shown in the following table:

~~119~~

	Three Months Ended				Nine Months Ended				Three Months Ended
	September 30				September 30				March 31,
	2008		2007		2008		2007		2009		2008
	(In millions)								(In millions)
JCP&L	$	26	$	30	$	67	$	71	$	19	$	19
Met-Ed		12		13		44		40		15		16
Penelec		8		7		25		22		9		8
Total	$	46	$	50	$	136	$	133
									$	43	$	43

Transition Bonds

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

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of ~~September 30, 2008, $377~~March 31, 2009, $363 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, ~~- principally~~which consists primarily of bondable transition property.

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

~~10.~~7. INCOME TAXES

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

Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate, if recognized in 2008. The majority of items that would not affect the 2008 effective tax rate would be purchase accounting adjustments to goodwill, if recognized in 2008. Upon completion of the federal tax ~~examinations~~examination for the 2007 tax ~~years 2004 to 2006~~year in the ~~third~~first quarter of ~~2008,~~2009, FirstEnergy recognized ~~approximately $45~~$13 million in tax benefits, ~~including $5 million that~~which favorably affected FirstEnergy’s effective tax rate. A majority of the tax benefits recognized in the third quarter of 2008 adjusted goodwill as a purchase accounting adjustment ($20 million) and accumulated deferred income taxes for temporary tax items ($15 million). During the first ~~nine~~three months of ~~2007,~~2008, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of ~~September 30, 2008,~~March 31, 2009, FirstEnergy expects that it is reasonably possible that ~~approximately $151~~$193 million of the unrecognized benefits may be resolved within the next twelve months, of which ~~$54 million to $147~~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, ~~capital~~ gains and losses recognized on the disposition of assets and various other tax items.

~~120~~105

FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. The reversal of accrued interest associated with the $45 million in recognized tax benefits favorably affected FirstEnergy’s effective tax rate by $12 million in the third quarter and first nine months of 2008 and an interest receivable of $4 million was removed from the accrued interest for FIN 48 items.taxes. The net amount of accumulated interest accrued as of ~~September 30, 2008~~March 31, 2009 was ~~$56~~$61 million, as compared to ~~$53~~$59 million as of December 31, ~~2007.~~2008. During the first three months of 2009 and 2008, there were no material changes to the amount of interest accrued.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from ~~2001-2007.~~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 ~~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 year 2009 in February 2009 under its Compliance Assurance Process program. Neither audit is expected to close before December ~~2008.~~2009. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

~~11.~~8. COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A) GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of ~~September 30, 2008,~~March 31, 2009, outstanding guarantees and other assurances aggregated approximately ~~$4.2~~$4.5 billion, consisting of parental guarantees - ~~$0.9~~$1.2 billion, subsidiaries’ guarantees - ~~$2.7~~$2.6 billion, surety bonds - $0.1 billion and LOCs - ~~$0.5~~$0.6 billion.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements ~~legally~~ obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4 billion (included in the ~~$0.9~~$1.2 billion discussed above) as of ~~September 30, 2008~~March 31, 2009 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of ~~September 30, 2008,~~March 31, 2009, FirstEnergy's maximum exposure under these collateral provisions was ~~$573~~$761 million, consisting of ~~$64~~$55 million due to “material adverse event” contractual clauses and ~~$509~~$706 million due to a below investment grade credit rating. Additionally, stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase this amount to ~~$648~~$830 million, consisting of ~~$58~~$54 million due to “material adverse event” contractual clauses and ~~$590~~$776 million due to a below investment grade credit rating.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of ~~$94~~$111 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

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

106

In July 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has ~~unconditionally~~fully and ~~irrevocably~~unconditionally guaranteed all of FGCO’s obligations under each of the leases (see Note ~~15)~~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.

~~121~~

On October 8, 2008, to enhance their liquidity position in the face of the turbulent credit and bond markets, FirstEnergy, ~~and its subsidiaries,~~ 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.

In early October 2008, FirstEnergy took steps to further enhance its liquidity position by negotiating with the banks that have issued irrevocable direct pay LOCs in support of its outstanding variable interest rate PCRBs to extend the respective reimbursement obligations of the applicable FirstEnergy subsidiary obligors in the event that such LOCs are drawn upon. FirstEnergy’s subsidiaries currently have approximately $2.1 billion variable interest rate PCRBs outstanding (FES - $1.9 billion, OE - $156 million, Met-Ed - $29 million and Penelec - $45 million). The LOCs supporting these PCRBs may be drawn upon to pay the purchase price to bondholders that have exercised the right to tender their PCRBs for mandatory purchase. As a result of these negotiations, a total of approximately $902 million of LOCs that previously required reimbursement within 30 days or less of a draw under the applicable LOC have now been modified to extend the reimbursement obligations to six months or June 2009, as applicable.

(B)	ENVIRONMENTAL MATTERS

Clean Air Act Compliance

~~122~~

107

~~123~~

108

National Ambient Air Quality Standards

Mercury Emissions

~~124~~

Climate Change

109

Clean Water Act

Regulation of ~~Hazardous~~ Waste Disposal

~~125~~110

The Utilities have been named as ~~PRPs~~potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all ~~PRPs~~potentially responsible parties for a particular site may be liable on a joint and several basis. ~~Therefore, environmental~~Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of ~~September 30, 2008,~~March 31, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately ~~$94~~$91 million (JCP&L - ~~$68~~- $64 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - ~~$24~~$25 million) have been accrued through ~~September 30, 2008.~~March 31, 2009. Included in the total ~~for JCP&L~~ are accrued liabilities of approximately ~~$57~~$56 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

Power Outages and Related Litigation

~~126~~

��

Nuclear Plant Matters

111

Other Legal Matters

~~127~~

~~12.~~9. REGULATORY MATTERS

(A) RELIABILITY INITIATIVES

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

~~(B) OHIO~~

On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007 the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the deferred fuel costs is addressed in the Ohio Companies’ comprehensive ESP filing, as described below. If the recovery of the deferred fuel costs is not resolved in the ESP, or in the event the MRO is implemented, recovery of the deferred fuel costs will be resolved in the proceeding that was instituted with the PUCO on February 8, 2008, as referenced above.

~~128~~112

(B) OHIO

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

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

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

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

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

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

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

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

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

~~129~~113

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

~~130~~

Major provisions of the legislation include:

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

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

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

114

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

~~131~~

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

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

(D) NEW JERSEY

115

~~On April 17, 2008, a draft EMP was released for public comment.~~ The ~~final~~ EMP was issued on October 22, 2008, ~~and establishes~~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;

~~132~~

·	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 ~~Design~~

116

~~133~~

Post Transition Period Rate Design

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

~~Interconnection Agreement with AMP-Ohio~~

Duquesne’s Request to Withdraw from PJM

In November, 2008, Duquesne and other parties, including FirstEnergy, negotiated a settlement that would, among other things, allow for Duquesne to remain in PJM and provide for ~~capacity auctions conducted prior~~a methodology for Duquesne to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. On January 17, 2008,meet the ~~FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne zone load-serving entities to pay their~~ PJM capacity obligations ~~through May 31, 2011.~~for the 2011-2012 auction that excluded the Duquesne load. The settlement agreement was filed on December 10, 2008 and approved by the FERC in an order issued on January 29, 2009. MISO opposed the settlement agreement pending resolution of exit fees alleged to be owed by Duquesne. The FERC did not resolve the exit fee issue in its order. On March 2, 2009, the PPUC filed for rehearing of the FERC's January 29, 2009 order approving the settlement. Thereafter, FirstEnergy and other parties filed in opposition to the rehearing request. The PPUC's rehearing request, and the pleadings in opposition thereto, are pending before the FERC.

~~134~~117

~~FirstEnergy desires to continue to use its Duquesne zone generation resources to serve load in PJM. On April 18, 2008, the FERC issued its Order on Motion~~Changes ordered for Emergency Clarification on whether Duquesne-zone generators could participate in PJM’s May 2008 auction for the 2011-2012 planning year. In the order, the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM these generators could contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with the FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction.

~~Complaint against PJM RPM~~Reliability Pricing Model (RPM) Auction

MISO Resource Adequacy Proposal

~~135~~

~~Organized Wholesale Power Markets~~

FES Sales to Affiliates

118

~~13.~~

10. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

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

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

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

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

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

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

In December 2007, the FASB issued SFAS 141(R), which: (i) requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction; (ii) establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and (iii) requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in deferred tax valuation allowances and income tax uncertainties made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. Under SFAS 141(R), adjustments to the acquired entity’s deferred tax assets and uncertain tax position balances occurring outside the measurement period will be recorded as a component of income tax expense, rather than goodwill. The impact of FirstEnergy’s application of this Standard in periods after implementation will be dependent upon acquisitions at that time.

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

~~136~~119

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

~~14.~~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.”

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

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

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

~~137~~

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

March 31, 2008
External revenues	$	2,212		$	329		$	707		$	40		$	(11	)	$	3,277
Internal revenues		-			776			-			-			(776	)		-
Total revenues		2,212			1,105			707			40			(787	)		3,277
Depreciation and amortization		255			53			4			-			5			317
Investment income (loss), net		45			(6	)		1			-			(23	)		17
Net interest charges		103			27			-			-			41			171
Income taxes		119			58			15			14			(19	)		187
Net income		179			87			23			22			(34	)		277
Total assets		23,211			8,108			257			281			558			32,415
Total goodwill		5,582			24			-			-			-			5,606
Property additions		255			462			-			12			(18	)		711

Segment Financial Information
Ohio
Energy Competitive Transitional
Delivery Energy Generation Reconciling
Three Months Ended Services Services Services Other Adjustments Consolidated
(In millions)
September 30, 2008
External revenues $ 2,657 $ 460 $ 813 $ 5 $ (31 ) $ 3,904
Internal revenues - 786 - - (786 ) -
Total revenues 2,657 1,246 813 5 (817 ) 3,904
Depreciation and amortization 286 67 46 1 1 401
Investment income 48 13 1 - (22 ) 40
Net interest charges 101 31 1 - 44 177
Income taxes 188 109 14 (46 ) (27 ) 238
Net income 283 164 19 48 (43 ) 471
Total assets 23,088 9,360 270 457 387 33,562
Total goodwill 5,559 24 - - - 5,583
Property additions 170 285 - 85 20 560

September 30, 2007
External revenues $ 2,520 $ 370 $ 723 $ 9 $ 19 $ 3,641
Internal revenues - 806 - - (806 ) -
Total revenues 2,520 1,176 723 9 (787 ) 3,641
Depreciation and amortization 299 51 (16 ) 1 8 343
Investment income 58 5 - 1 (34 ) 30
Net interest charges 117 39 - 1 37 194
Income taxes 175 99 11 (2 ) (10 ) 273
Net income 269 148 16 6 (26 ) 413
Total assets 23,308 7,182 268 232 663 31,653
Total goodwill 5,585 24 - - - 5,609
Property additions 209 199 - 3 19 430

Nine Months Ended

September 30, 2008
External revenues $ 7,051 $ 1,164 $ 2,203 $ 65 $ (57 ) $ 10,426
Internal revenues - 2,266 - - (2,266 ) -
Total revenues 7,051 3,430 2,203 65 (2,323 ) 10,426
Depreciation and amortization 782 179 61 2 10 1,034
Investment income 133 (1 ) 1 6 (66 ) 73
Net interest charges 303 86 1 - 133 523
Income taxes 436 212 42 (33 ) (72 ) 585
Net income 655 317 62 96 (120 ) 1,010
Total assets 23,088 9,360 270 457 387 33,562
Total goodwill 5,559 24 - - - 5,583
Property additions 621 1,430 - 106 20 2,177

September 30, 2007
External revenues $ 6,655 $ 1,089 $ 1,968 $ 29 $ (18 ) $ 9,723
Internal revenues - 2,210 - - (2,210 ) -
Total revenues 6,655 3,299 1,968 29 (2,228 ) 9,723
Depreciation and amortization 767 153 (80 ) 3 20 863
Investment income 190 13 1 1 (112 ) 93
Net interest charges 340 131 1 3 97 572
Income taxes 464 259 46 - (74 ) 695
Net income 695 388 69 13 (124 ) 1,041
Total assets 23,308 7,182 268 232 663 31,653
Total goodwill 5,585 24 - - - 5,609
Property additions 609 462 - 6 50 1,127

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

~~138~~120

~~15.~~12. SUPPLEMENTAL GUARANTOR INFORMATION

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully and unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty. This transaction is classified as an operating lease under GAAP for FES and ~~FirstEnergy and~~ a financing for FGCO.

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

~~139~~121

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

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

REVENUES $ 1,222,783 $ 574,394 $ 267,017 $ (822,590 ) $ 1,241,604

EXPENSES:
Fuel 8,177 307,646 34,123 - 349,946
Purchased power from non-affiliates 221,493 - - - 221,493
Purchased power from affiliates 815,243 7,347 15,821 (822,590 ) 15,821
Other operating expenses 35,596 110,701 120,697 12,190 279,184
Provision for depreciation 1,978 33,432 30,559 (1,336 ) 64,633
General taxes 4,829 10,768 6,139 - 21,736
Total expenses 1,087,316 469,894 207,339 (811,736 ) 952,813
- - - -
OPERATING INCOME 135,467 104,500 59,678 (10,854 ) 288,791

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees 102,777 (515 ) 13,287 (97,122 ) 18,427
Interest expense - affiliates (120 ) (4,963 ) (2,932 ) - (8,015 )
Interest expense - other (8,464 ) (23,447 ) (17,183 ) 16,325 (32,769 )
Capitalized interest 41 11,376 978 - 12,395
Total other income (expense) 94,234 (17,549 ) (5,850 ) (80,797 ) (9,962 )

INCOME BEFORE INCOME TAXES 229,701 86,951 53,828 (91,651 ) 278,829

INCOME TAXES 44,046 31,863 14,995 2,270 93,174

NET INCOME $ 185,655 $ 55,088 $ 38,833 $ (93,921 ) $ 185,655

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

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

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

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

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

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

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

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

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

~~140~~122

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended September 30, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)

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

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

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

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

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

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

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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

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

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

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

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

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

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

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

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

~~141~~123

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

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

REVENUES $ 3,387,258 $ 1,707,320 $ 879,729 $ (2,562,309 ) $ 3,411,998

EXPENSES:
Fuel 13,920 876,077 92,188 - 982,185
Purchased power from non-affiliates 648,556 - - - 648,556
Purchased power from affiliates 2,549,892 12,417 75,834 (2,562,309 ) 75,834
Other operating expenses 103,034 342,041 381,826 36,567 863,468
Provision for depreciation 3,885 90,058 80,646 (4,054 ) 170,535
General taxes 14,971 33,842 15,915 - 64,728
Total expenses 3,334,258 1,354,435 646,409 (2,529,796 ) 2,805,306

OPERATING INCOME 53,000 352,885 233,320 (32,513 ) 606,692

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees 323,092 (1,234 ) (2,699 ) (305,710 ) 13,449
Interest expense - affiliates (252 ) (18,172 ) (7,529 ) - (25,953 )
Interest expense - other (19,105 ) (73,112 ) (38,833 ) 49,241 (81,809 )
Capitalized interest 90 27,460 2,049 - 29,599
Total other income (expense) 303,825 (65,058 ) (47,012 ) (256,469 ) (64,714 )

INCOME BEFORE INCOME TAXES 356,825 287,827 186,308 (288,982 ) 541,978

INCOME TAXES 13,092 109,615 68,597 6,941 198,245

NET INCOME $ 343,733 $ 178,212 $ 117,711 $ (295,923 ) $ 343,733

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

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

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

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

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

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

CAPITALIZATION:
Common stockholder's equity		3,120,406		1,901,085		1,797,764		(3,698,849	)		3,120,406
Long-term debt and other long-term obligations		21,819		1,466,373		469,839		(1,287,970	)		670,061
		3,142,225		3,367,458		2,267,603		(4,986,819	)		3,790,467

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,018,156			1,018,156
Accumulated deferred income taxes		-		-		203,899		(203,899	)		-
Accumulated deferred investment tax credits		-		38,669		22,976		-			61,645
Asset retirement obligations		-		24,274		852,799		-			877,073
Retirement benefits		23,242		175,561		-		-			198,803
Property taxes		-		27,494		22,610		-			50,104
Lease market valuation liability		-		296,376		-		-			296,376
Other		17,916		17,509		51,205		-			86,630
		41,158		579,883		1,153,489		814,257			2,588,787
	$	4,754,819	$	5,661,728	$	4,939,289	$	(4,482,809	)	$	10,873,027

~~142~~124

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Nine Months Ended September 30, 2007
FES �� FGCO NGC Eliminations Consolidated
(In thousands)

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

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

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

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

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

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

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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2008	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	-	$	39	$	-	$	-		$	39
Receivables-
Customers		86,123		-		-		-			86,123
Associated companies		363,226		225,622		113,067		(323,815	)		378,100
Other		991		11,379		12,256		-			24,626
Notes receivable from associated companies		107,229		21,946		-		-			129,175
Materials and supplies, at average cost		5,750		303,474		212,537		-			521,761
Prepayments and other		76,773		35,102		660		-			112,535
		640,092		597,562		338,520		(323,815	)		1,252,359

PROPERTY, PLANT AND EQUIPMENT:
In service		134,905		5,420,789		4,705,735		(389,525	)		9,871,904
Less - Accumulated provision for depreciation		13,090		2,702,110		1,709,286		(169,765	)		4,254,721
		121,815		2,718,679		2,996,449		(219,760	)		5,617,183
Construction work in progress		4,470		1,441,403		301,562		-			1,747,435
		126,285		4,160,082		3,298,011		(219,760	)		7,364,618

INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,033,717		-			1,033,717
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		3,596,152		-		-		(3,596,152	)		-
Other		1,913		59,476		202		-			61,591
		3,598,065		59,476		1,096,819		(3,596,152	)		1,158,208

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		24,703		476,611		-		(233,552	)		267,762
Lease assignment receivable from associated companies		-		71,356		-		-			71,356
Goodwill		24,248		-		-		-			24,248
Property taxes		-		27,494		22,610		-			50,104
Unamortized sale and leaseback costs		-		20,286		-		49,646			69,932
Other		59,642		59,674		21,743		(44,625	)		96,434
		108,593		655,421		44,353		(228,531	)		579,836
	$	4,473,035	$	5,472,541	$	4,777,703	$	(4,368,258	)	$	10,355,021

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	5,377	$	925,234	$	1,111,183	$	(16,896	)	$	2,024,898
Short-term borrowings-
Associated companies		1,119		257,357		6,347		-			264,823
Other		1,000,000		-		-		-			1,000,000
Accounts payable-
Associated companies		314,887		221,266		250,318		(314,133	)		472,338
Other		35,367		119,226		-		-			154,593
Accrued taxes		8,272		60,385		30,790		(19,681	)		79,766
Other		61,034		136,867		13,685		36,853			248,439
		1,426,056		1,720,335		1,412,323		(313,857	)		4,244,857

CAPITALIZATION:
Common stockholder's equity		2,944,423		1,832,678		1,752,580		(3,585,258	)		2,944,423
Long-term debt and other long-term obligations		61,508		1,328,921		469,839		(1,288,820	)		571,448
		3,005,931		3,161,599		2,222,419		(4,874,078	)		3,515,871

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,026,584			1,026,584
Accumulated deferred income taxes		-		-		206,907		(206,907	)		-
Accumulated deferred investment tax credits		-		39,439		23,289		-			62,728
Asset retirement obligations		-		24,134		838,951		-			863,085
Retirement benefits		22,558		171,619		-		-			194,177
Property taxes		-		27,494		22,610		-			50,104
Lease market valuation liability		-		307,705		-		-			307,705
Other		18,490		20,216		51,204		-			89,910
		41,048		590,607		1,142,961		819,677			2,594,293
	$	4,473,035	$	5,472,541	$	4,777,703	$	(4,368,258	)	$	10,355,021

~~143~~125

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of September 30, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2 $ - $ - $ - $ 2
Receivables-
Customers 137,126 - - - 137,126
Associated companies 267,777 195,005 100,481 (299,484 ) 263,779
Other 910 1,595 20,419 - 22,924
Notes receivable from associated companies 118,526 38,400 - - 156,926
Materials and supplies, at average cost 3,519 288,623 205,134 - 497,276
Prepayments and other 64,585 84,138 30,807 - 179,530
592,445 607,761 356,841 (299,484 ) 1,257,563

PROPERTY, PLANT AND EQUIPMENT:
In service 108,733 5,413,310 4,704,478 (391,859 ) 9,834,662
Less - Accumulated provision for depreciation 10,990 2,712,638 1,658,863 (170,774 ) 4,211,717
97,743 2,700,672 3,045,615 (221,085 ) 5,622,945
Construction work in progress 2,827 1,225,381 157,444 - 1,385,652
100,570 3,926,053 3,203,059 (221,085 ) 7,008,597
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts - - 1,145,384 - 1,145,384
Long-term notes receivable from associated companies - - 62,900 - 62,900
Investment in associated companies 3,581,979 - - (3,581,979 ) -
Other 2,124 38,247 202 - 40,573
3,584,103 38,247 1,208,486 (3,581,979 ) 1,248,857
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes 9,655 471,718 - (251,032 ) 230,341
Lease assignment receivable from associated companies - 71,356 - - 71,356
Goodwill 24,248 - - - 24,248
Property taxes - 25,007 22,767 - 47,774
Pension assets 3,208 11,556 - - 14,764
Unamortized sale and leaseback costs - 8,445 - 48,920 57,365
Other 18,343 59,511 18,717 (46,869 ) 49,702
55,454 647,593 41,484 (248,981 ) 495,550
$ 4,332,572 $ 5,219,654 $ 4,809,870 $ (4,351,529 ) $ 10,010,567
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 4,679 $ 873,562 $ 1,077,289 $ (17,315 ) $ 1,938,215
Short-term borrowings-
Associated companies - 147,108 164,642 - 311,750
Other 1,000,000 - - - 1,000,000
Accounts payable-
Associated companies 276,155 202,678 158,215 (275,601 ) 361,447
Other 36,724 126,449 - - 163,173
Accrued taxes 4,109 88,826 17,661 (29,877 ) 80,719
Other 36,491 116,637 26,777 38,009 217,914
1,358,158 1,555,260 1,444,584 (284,784 ) 4,073,218
CAPITALIZATION:
Common stockholder's equity 2,916,934 1,813,911 1,755,054 (3,568,965 ) 2,916,934
Long-term debt and other long-term obligations 40,333 1,364,207 451,365 (1,296,982 ) 558,923
2,957,267 3,178,118 2,206,419 (4,865,947 ) 3,475,857
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction - - - 1,035,013 1,035,013
Accumulated deferred income taxes - - 235,811 (235,811 ) -
Accumulated deferred investment tax credits - 40,209 23,759 - 63,968
Asset retirement obligations - 24,148 825,327 - 849,475
Retirement benefits 9,745 57,822 - - 67,567
Property taxes - 25,328 22,767 - 48,095
Lease market valuation liability - 319,129 - - 319,129
Other 7,402 19,640 51,203 - 78,245
17,147 486,276 1,158,867 799,202 2,461,492
$ 4,332,572 $ 5,219,654 $ 4,809,870 $ (4,351,529 ) $ 10,010,567

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

~~144~~126

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

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

NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES	$	273,827		$	(122,171	)	$	8,108		$	188		$	159,952

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		400,000			646,975			234,921			-			1,281,896
Redemptions and Repayments-
Long-term debt		-			(135,063	)		(153,540	)		-			(288,603	)
Common stock dividend payments		(10,000	)		-			-			-			(10,000	)
Net cash provided from financing activities		390,000			511,912			81,381			-			983,293

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(19,406	)		(375,391	)		(81,545	)		(187	)		(476,529	)
Proceeds from asset sales		-			5,088			-			-			5,088
Sales of investment securities held in trusts		-			-			173,123			-			173,123
Purchases of investment securities held in trusts		-			-			(181,079	)		-			(181,079	)
Loans to associated companies, net		(644,604	)		-			-			-			(644,604	)
Other		183			(19,438	)		12			(1	)		(19,244	)
Net cash used for investing activities		(663,827	)		(389,741	)		(89,489	)		(188	)		(1,143,245	)

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

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of December 31, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2 $ - $ - $ - $ 2
Receivables-
Customers 133,846 - - - 133,846
Associated companies 327,715 237,202 98,238 (286,656 ) 376,499
Other 2,845 978 - - 3,823
Notes receivable from associated companies 23,772 - 69,012 - 92,784
Materials and supplies, at average cost 195 215,986 210,834 - 427,015
Prepayments and other 67,981 21,605 2,754 - 92,340
556,356 475,771 380,838 (286,656 ) 1,126,309
PROPERTY, PLANT AND EQUIPMENT:
In service 25,513 5,065,373 3,595,964 (392,082 ) 8,294,768
Less - Accumulated provision for depreciation 7,503 2,553,554 1,497,712 (166,756 ) 3,892,013
18,010 2,511,819 2,098,252 (225,326 ) 4,402,755
Construction work in progress 1,176 571,672 188,853 - 761,701
19,186 3,083,491 2,287,105 (225,326 ) 5,164,456
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts - - 1,332,913 - 1,332,913
Long-term notes receivable from associated companies - - 62,900 - 62,900
Investment in associated companies 2,516,838 - - (2,516,838 ) -
Other 2,732 37,071 201 - 40,004
2,519,570 37,071 1,396,014 (2,516,838 ) 1,435,817
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes 16,978 522,216 - (262,271 ) 276,923
Lease assignment receivable from associated companies - 215,258 - - 215,258
Goodwill 24,248 - - - 24,248
Property taxes - 25,007 22,767 - 47,774
Pension asset 3,217 13,506 - - 16,723
Unamortized sale and leaseback costs - 27,597 - 43,206 70,803
Other 22,956 52,971 6,159 (38,133 ) 43,953
67,399 856,555 28,926 (257,198 ) 695,682
$ 3,162,511 $ 4,452,888 $ 4,092,883 $ (3,286,018 ) $ 8,422,264
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ - $ 596,827 $ 861,265 $ (16,896 ) $ 1,441,196
Short-term borrowings-
Associated companies - 238,786 25,278 - 264,064
Other 300,000 - - - 300,000
Accounts payable-
Associated companies 287,029 175,965 268,926 (286,656 ) 445,264
Other 56,194 120,927 - - 177,121
Accrued taxes 18,831 125,227 28,229 (836 ) 171,451
Other 57,705 131,404 11,972 36,725 237,806
719,759 1,389,136 1,195,670 (267,663 ) 3,036,902
CAPITALIZATION:
Common stockholder's equity 2,414,231 951,542 1,562,069 (2,513,611 ) 2,414,231
Long-term debt and other long-term obligations - 1,597,028 242,400 (1,305,716 ) 533,712
2,414,231 2,548,570 1,804,469 (3,819,327 ) 2,947,943
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction - - - 1,060,119 1,060,119
Accumulated deferred income taxes - - 259,147 (259,147 ) -
Accumulated deferred investment tax credits - 36,054 25,062 - 61,116
Asset retirement obligations - 24,346 785,768 - 810,114
Retirement benefits 8,721 54,415 - - 63,136
Property taxes - 25,328 22,767 - 48,095
Lease market valuation liability - 353,210 - - 353,210
Other 19,800 21,829 - - 41,629
28,521 515,182 1,092,744 800,972 2,437,419
$ 3,162,511 $ 4,452,888 $ 4,092,883 $ (3,286,018 ) $ 8,422,264

~~145~~

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

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

NET CASH PROVIDED FROM OPERATING ACTIVITIES: $ 47,463 $ 267,933 $ 247,054 $ (8,317 ) $ 554,133

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt - 328,325 209,050 - 537,375
Equity contribution from parent 280,000 675,000 175,000 (850,000 ) 280,000
Short-term borrowings, net 700,000 - 139,363 (91,677 ) 747,686
Redemptions and Repayments-
Long-term debt (1,777 ) (286,776 ) (180,666 ) 8,317 (460,902 )
Short-term borrowings, net - (91,677 ) - 91,677 -
Common stock dividend payment (43,000 ) - - - (43,000 )
Net cash provided from financing activities 935,223 624,872 342,747 (841,683 ) 1,061,159

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (38,481 ) (778,329 ) (600,395 ) - (1,417,205 )
Proceeds from asset sales - 15,218 - - 15,218
Sales of investment securities held in trusts - - 596,291 - 596,291
Purchases of investment securities held in trusts - - (624,899 ) - (624,899 )
Loan repayments from (loans to) associated companies, net (94,755 ) (38,399 ) 69,012 - (64,142 )
Investment in subsidiary (850,000 ) - - 850,000 -
Restricted funds for debt redemption - (52,090 ) (29,550 ) - (81,640 )
Other 550 (39,205 ) (260 ) - (38,915 )
Net cash used for investing activities (982,686 ) (892,805 ) (589,801 ) 850,000 (1,615,292 )

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

~~146~~

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Nine Months Ended September 30, 2007 FES FGCO NGC Eliminations Consolidated
(In thousands)

NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES $ (7,937 ) $ 350,927 $ 179,037 $ - $ 522,027

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt - 1,328,919 - (1,328,919 ) -
Equity contribution from parent 700,000 700,000 - (700,000 ) 700,000
Short-term borrowings, net 223,942 - 13,128 (237,070 ) -
Redemptions and Repayments-
Common stock (600,000 ) - - - (600,000 )
Long-term debt - (795,019 ) (315,155 ) - (1,110,174 )
Short-term borrowings, net - (1,022,197 ) - 237,070 (785,127 )
Common stock dividend payment (67,000 ) - - - (67,000 )
Net cash provided from (used for) financing activities 256,942 211,703 (302,027 ) (2,028,919 ) (1,862,301 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (10,119 ) (332,499 ) (140,289 ) - (482,907 )
Proceeds from asset sales - 12,990 - - 12,990
Proceeds from sale and leaseback transaction - - - 1,328,919 1,328,919
Sales of investment securities held in trusts - - 521,535 - 521,535
Purchases of investment securities held in trusts - - (552,779 ) - (552,779 )
Loan repayments from (loans to) associated companies, net 460,023 (242,612 ) 292,896 - 510,307
Investment in subsidiary (700,000 ) - 700,000 -
Other 1,091 (509 ) 1,627 - 2,209
Net cash provided from (used for) investing activities (249,005 ) (562,630 ) 122,990 2,028,919 1,340,274

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

~~147~~127

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 chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of the registrant's disclosure controls and ~~procedures.~~procedures as of the end of the period covered by this report. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that the registrant's disclosure controls and procedures are effective ~~and were designed to bring to their attention material information relating to~~as of the ~~registrant and its consolidated subsidiaries~~end of the period covered by ~~others within those entities.~~this report.

(b) CHANGES IN INTERNAL CONTROLS

During the quarter ended ~~September 30, 2008,~~March 31, 2009, there were no changes in FirstEnergy’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’s internal control over financial reporting.

ITEM 4T. CONTROLS AND PROCEDURES – FES, OE, CEI, TE, JCP&L, MET-ED AND PENELEC

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Each registrant's chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of such registrant's disclosure controls and ~~procedures.~~procedures as of the end of the period covered by this report. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that such registrant's disclosure controls and procedures are effective ~~and were designed to bring to their attention material information relating to such registrant and its consolidated subsidiaries~~as of the end of the period covered by ~~others within those entities.~~this report.

(b) CHANGES IN INTERNAL CONTROLS

During the quarter ended ~~September 30, 2008,~~March 31, 2009, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.

~~148~~128

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 108 and 119 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, ~~2007, and Quarterly Report on Form 10-Q for the quarter ended June 30,~~ 2008 ~~include~~includes a detailed discussion of its risk factors. The information presented below updates certain of those risk factors and should be read in conjunction with the risk factors and information disclosed in FirstEnergy’s ~~prior SEC filings.~~Annual Report on Form 10-K.

~~FirstEnergy relies on access~~FES’ Business is Affected By Competitive Procurement Processes Approved by State Regulators

The adoption of competitive bid processes for PLR generation supply in Ohio and Pennsylvania may affect the amount of generation that FES sells to its utility affiliates in those states. For example, the ~~credit~~Amended ESP approved by the PUCO established a competitive bid process for generation supply and ~~capital~~pricing for a two-year period beginning June 1, 2009 through May 31, 2011. FES intends to participate in the CBP as a supplier and its results of operations and financial condition will be impacted by the price and the percentage of the load for which it is ultimately the supplier.

Competitive Power Markets

FES’ financial performance depends upon its success in competing in wholesale and retail markets in MISO and PJM. FES’ ability to ~~finance a portion~~compete successfully in these markets is affected by, among other things, the efficiency and cost structure of its ~~working capital requirements~~generation fleet, market prices, demand for electricity, effectiveness of risk management practices and ~~to support its liquidity needs. Access to these markets may be adversely affected~~the market rules established by ~~factors beyond FirstEnergy’s control, including turmoil in the financial services industry, volatility in securities trading markets~~state and general economic downturns. In particular, recent disruptions in the variable-rate demand bond markets could require utilization of a significant portion of the sources of liquidity currently available to FirstEnergy and its subsidiaries.

FirstEnergy relies upon access to the credit and capital markets as a source of liquidity for the portion of its working capital requirements not provided by cash from operations and to comply with various regulatory requirements. Market disruptions such as those currently being experienced in the United States and abroad may increase FirstEnergy’s cost of borrowing or adversely affect its ability to access sources of liquidity upon which it relies to finance operations and satisfy obligations as they become due. These disruptions may include turmoil in the financial services industry, including substantial uncertainty surrounding particular lending institutions and counterparties with whom FirstEnergy does business, unprecedented volatility in the markets where FirstEnergy’s outstanding securities trade, and general economic downturns in the areas where FirstEnergy does business. If FirstEnergy is unable to access credit at competitive rates, or if its short-term or long-term borrowing costs dramatically increase, FirstEnergy’s ability to finance its operations, meet its short-term obligations and implement its operating strategy could be adversely affected.federal regulators.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common ~~stock.~~stock during the first quarter of 2009.

Period
July 1-31, August 1-31, September 1-30, Third

2008

2008

2008

Quarter

Total Number of Shares Purchased (a)
52,166 32,187 208,772 293,125
Average Price Paid per Share $81.63 $71.63 $72.09 $73.74
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
- - - -

	Period
	January	February	March	First Quarter
Total Number of Shares Purchased (a)	23,535	20,090	887,792	931,417
Average Price Paid per Share	$50.09	$46.20	$41.34	$41.67
Total Number of Shares Purchased
As Part of Publicly Announced Plans
or Programs	-	-	-	-
Maximum Number (or Approximate Dollar
Value) of Shares that May Yet Be
Purchased Under the Plans or Programs	-	-	-	-

(a)

Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan, and shares purchased as part of publicly announced plans.

~~149~~129

ITEM 6. EXHIBITS

Exhibit Number



FirstEnergy
	10.1		~~$U.S. 300,000,000 Credit~~Form of Director Indemnification Agreement dated as of October 8, 2008, among FirstEnergy Generation Corp., as Borrower, FirstEnergy Corp. and FirstEnergy Solutions Corp., as Guarantors, Credit Suisse and the other Banks parties thereto from time to time, as Banks, and Credit Suisse, as Administrative Agent
	10.2		Form of Management Director Indemnification Agreement
	12		Fixed charge ratios
	15		Letter from independent registered public accounting firm
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101*		The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the three months ended March 31, 2009, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.
FES
		4.1	Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, of FirstEnergy Generation Corp. to The Bank of New York Trust Company, N.A., as Trustee
		4.1(a)	First Supplemental Indenture dated as of June 25, 2008 providing among other things for First Mortgage Bonds, Guarantee Series A of 2008 due 2009 and First Mortgage Bonds, Guarantee Series B of 2008 due 2009
		4.1(b)	Second Supplemental Indenture dated as of March 1, 2009 providing among other things for First Mortgage Bonds, Guarantee Series A of 2009 due 2014 and First Mortgage Bonds, Guarantee Series B of 2009 due 2023
		4.1(c)	Third Supplemental Indenture dated as of March 31, 2009 providing among other things for First Mortgage Bonds, Collateral Series A of 2009 due 2011
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
~~FES~~
		~~4.1~~	~~Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, of FirstEnergy Generation Corp. to The Bank of New York Trust Company, N.A., as Trustee~~
		~~10.1~~	$U.S. 300,000,000 Credit Agreement, dated as of October 8, 2008, among FirstEnergy Generation Corp., as Borrower, FirstEnergy Corp. and FirstEnergy Solutions Corp., as Guarantors, Credit Suisse and the other Banks parties thereto from time to time, as Banks, and Credit Suisse, as Administrative Agent
		~~10.2~~	~~Third Restated Partial Requirements Agreement dated November 1, 2008~~
		~~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
		~~4.1~~	Fourteenth Supplemental Indenture, dated as of October 1, 2008, to Ohio Edison Company’s General Mortgage Indenture and Deed of Trust dated as of January 1, 1998 (incorporated by reference to October 22, 2008 Form 8-K, Exhibit 4.1)
		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~~
		12	Fixed charge ratios
		15	Letter from independent registered public accounting firm
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
TE CEI
		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~~ TE
		4.1	First Supplemental Indenture, dated as of April 24, 2009, between the Toledo Edison Company and The Bank of New York Mellon Trust Company, N.A., as trustee to the Indenture dated as of November 1, 2006 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.1)
		4.2	Officer’s Certificate (including the Form of the 7.25% Senior Secured Notes due 2020), dated April 24, 2009 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.2)
		4.3	Fifty-sixth Supplemental Indenture, dated as of April 23, 2009, between The Toledo Edison Company and JPMorgan Chase Bank, N.A., as trustee, to the Indenture of Mortgage and Deed of Trust dated as of April 1, 1947 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.3)
		4.4	Fifty-seventh Supplemental Indenture, dated as of April 24, 2009, between the Toledo Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee, to the Indenture of Mortgage and Deed of Trust dated as of April 1, 1947 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.4)
		4.5	Form of First Mortgage Bonds, 7.25% Series of 2009 Due 2020 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.5)
		12	Fixed charge ratios
		15	Letter from independent registered public accounting firm
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
~~Met-Ed~~ JCP&L
		~~10.2~~	~~Third Restated Partial Requirements Agreement dated November 1, 2008~~
		12	~~Fixed charge ratios~~
		15	~~Letter from independent registered public accounting firm~~
		~~31.1~~	~~Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)~~
		~~31.2~~	~~Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)~~
		32	~~Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350~~
~~Penelec~~
		~~10.2~~	~~Third Restated Partial Requirements Agreement dated November 1, 2008~~
		12	Fixed charge ratios
		15	Letter from independent registered public accounting firm
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

130

Met-Ed
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
Penelec
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

* Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited and the purpose of submitting these XBRL-Related Documents is to test the related format and technology and, as a result, investors should not rely on the XBRL-Related Documents in making investment decisions. Furthermore, users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

Pursuant to reporting requirements of respective financings, FirstEnergy, OE, CEI, TE, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.

~~150~~131

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

~~November~~May 7, ~~2008~~2009

	FIRSTENERGY ~~CORP.~~CORP.
	Registrant

	FIRSTENERGY SOLUTIONS CORP.
	Registrant

	OHIO EDISON COMPANY
	Registrant

	THE CLEVELAND ELECTRIC
	ILLUMINATING COMPANY
	Registrant

	THE TOLEDO EDISON COMPANY
	Registrant

	METROPOLITAN EDISON COMPANY
	Registrant

	PENNSYLVANIA ELECTRIC COMPANY
	Registrant

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

	JERSEY CENTRAL POWER & LIGHT COMPANY
	Registrant



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

~~151~~132

Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.

333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

333-145140-01	FIRSTENERGY SOLUTIONS CORP.	31-1560186
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3583	THE TOLEDO EDISON COMPANY	34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

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

1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3522	PENNSYLVANIA ELECTRIC COMPANY	25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

Yes (X) No ( )	FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company
Yes ( ) No (X)	FirstEnergy Solutions Corp.

Large Accelerated Filer (X)	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 ~~November 6, 2008~~May 7, 2009
FirstEnergy Corp., $0.10 par value	304,835,407
FirstEnergy Solutions Corp., no par value	7
Ohio Edison Company, no par value	60
The Cleveland Electric Illuminating Company, no par value	67,930,743
The Toledo Edison Company, $5 par value	29,402,054
Jersey Central Power & Light Company, $10 par value	~~14,421,637~~ 13,628,447
Metropolitan Edison Company, no par value	859,500
Pennsylvania Electric Company, $20 par value	4,427,577

~~Jersey Central Power & Light~~Pennsylvania Electric Company		~~Pages~~

	Management's Narrative Analysis of Results of Operations	78-79
	Report of Independent Registered Public Accounting Firm	80
	Consolidated Statements of Income and Comprehensive Income	81
	Consolidated Balance Sheets	82
	Consolidated Statements of Cash Flows	83

~~Metropolitan Edison Company~~

	~~Management's Narrative Analysis of Results of Operations~~	~~84-85~~
	~~Report of Independent Registered Public Accounting Firm~~	86
	~~Consolidated Statements of Income and Comprehensive Income~~	87
	~~Consolidated Balance Sheets~~	88
	~~Consolidated Statements of Cash Flows~~	89

~~Pennsylvania Electric Company~~

	~~Management's Narrative Analysis of Results of Operations~~	~~90-91~~
	~~Report of Independent Registered Public Accounting Firm~~	92
	~~Consolidated Statements of Income and Comprehensive Income~~	93
	~~Consolidated Balance Sheets~~	94
	~~Consolidated Statements of Cash Flows~~	95

Combined Management’s Discussion and Analysis of Registrant Subsidiaries		~~96-111~~84-97

Combined Notes to Consolidated Financial Statements		~~112-147~~98-127

Item 3. Quantitative and Qualitative Disclosures About Market Risk.		~~148~~128

Item 4. Controls and Procedures – FirstEnergy.		~~148~~128

Item 4T. Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.		~~148~~128

Part II. Other Information

Item 1. Legal Proceedings.		~~149~~129

Item 1A. Risk Factors.		~~149~~129

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.		~~149~~129

Item 6. Exhibits.		~~150~~130-131

		Pages

Glossary of Terms		iii-v

Part I. Financial Information

Items 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	1-35
	Results of Operations	~~1-46~~
	Report of Independent Registered Public Accounting Firm	4736
	Consolidated Statements of Income	4837
	Consolidated Statements of Comprehensive Income	4938
	Consolidated Balance Sheets	5039
	Consolidated Statements of Cash Flows	5140

FirstEnergy Solutions Corp.

	Management's Narrative Analysis of Results of Operations	~~52-54~~41-43
	Report of Independent Registered Public Accounting Firm	5544
	Consolidated Statements of Income and Comprehensive Income	5645
	Consolidated Balance Sheets	5746
	Consolidated Statements of Cash Flows	5847

Ohio Edison Company

	Management's Narrative Analysis of Results of Operations	~~59-60~~48-49
	Report of Independent Registered Public Accounting Firm	6150
	Consolidated Statements of Income and Comprehensive Income	6251
	Consolidated Balance Sheets	6352
	Consolidated Statements of Cash Flows	6453

The Cleveland Electric Illuminating Company

	Management's Narrative Analysis of Results of Operations	~~65-66~~54-55
	Report of Independent Registered Public Accounting Firm	6756
	Consolidated Statements of Income and Comprehensive Income	6857
	Consolidated Balance Sheets	6958
	Consolidated Statements of Cash Flows	7059

The Toledo Edison Company

	Management's Narrative Analysis of Results of Operations	~~71-73~~60-61
	Report of Independent Registered Public Accounting Firm	62
	Consolidated Statements of Income and Comprehensive Income	63
	Consolidated Balance Sheets	64
	Consolidated Statements of Cash Flows	65

ATSI	American Transmission Systems, ~~Incorporated,~~Inc., 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	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 ~~formerly known as Bull Mountain~~
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
Utilities	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
Waverly	The Waverly Power and Light Company, a wholly owned subsidiary of Penelec

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

~~ACO~~	~~Administrative Consent Order~~
AEP	American Electric Power Company, Inc.
ALJ	Administrative Law Judge
~~AMP-Ohio~~	~~American Municipal Power-Ohio, Inc.~~
AOCL	Accumulated Other Comprehensive Loss
~~ARB~~AQC	~~Accounting Research Bulletin~~
~~ARO~~	~~Asset Retirement Obligation~~
~~ASM~~	~~Ancillary Services Market~~	Air Quality Control
BGS	Basic Generation Service
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CBP	Competitive Bid Process
CO2	Carbon Dioxide
~~DFI~~CTC	~~Demand for Information~~Competitive Transition Charge
DOJ	United States Department of Justice
~~DRA~~DPA	Department of the Public Advocate, Division of ~~Ratepayer Advocate~~
~~EIS~~	~~Energy Independence Strategy~~Rate Counsel
EITF	Emerging Issues Task Force
EMP	Energy Master Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ESP	Electric Security Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 48	FIN 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109”

~~FIN 47~~	~~FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB~~ ~~Statement No. 143"~~
~~FIN 48~~	~~FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement~~ ~~No. 109”~~
FMB	First Mortgage Bond
FSP	FASB Staff Position
FSP FAS 107-1 and APB 28-1	FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments”
FSP FAS 115-1 and SFAS 124-1	FSP FAS 115-1 and SFAS 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments”
FSP FAS 115-2 and FAS 124-2	FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments”
FSP FAS 132(R)-1	FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”
FSP FAS 157-4	FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
FTR	Financial Transmission Rights
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
ICE	Intercontinental Exchange
IRS	Internal Revenue Service
~~ISO~~	~~Independent System Operator~~
kV	Kilovolt
KWH	Kilowatt-hours
LED	Light-emitting Diode
LIBOR	London Interbank Offered Rate
LOC	Letter of Credit
MEIUG	Met-Ed Industrial Users Group
~~MEW~~	~~Mission Energy Westside, Inc.~~
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service, Inc.
MRO	Market Rate Offer
MW	Megawatts
MWH	Megawatt-hours
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
NOV	Notice of Violation
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
NYMEX	New York Mercantile Exchange
~~OCA~~OPEB	~~Office of Consumer Advocate~~
~~OTC~~	~~Over the Counter~~Other Post-Employment Benefits
OVEC	Ohio Valley Electric Corporation
PCRB	Pollution Control Revenue Bond
PICA	Penelec Industrial Customer Alliance
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last ~~Resort~~Resort; an electric utility’s obligation to provide generation service to customers whose alternative supplier fails to deliver service
PPUC	Pennsylvania Public Utility Commission
~~PRP~~	~~Potentially Responsible Party~~
PSA	Power Supply Agreement
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RECB	Regional Expansion Criteria and Benefits
RFP	Request for Proposal
~~RPM~~	~~Reliability Pricing Model~~
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Service
SB221	Amended Substitute Senate Bill 221
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
SFAS	Statement of Financial Accounting Standards

SFAS 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 142~~	~~SFAS No. 142, “Goodwill and Other Intangible Assets”~~
~~SFAS 143~~	~~SFAS No. 143, “Accounting for Asset Retirement Obligations”~~
SFAS 157	SFAS No. 157, “Fair Value Measurements”
SFAS ~~159~~160	SFAS No. ~~159, “The Fair Value Option for~~160, “Noncontrolling Interests in Consolidated Financial ~~Assets and Financial Liabilities~~Statements – ~~Including~~ an Amendment ~~Amendment~~ of ~~FASB Statement~~ARB No. ~~115”~~51”
SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
TBC	Transition Bond Charge
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
TSC	Transmission Service Charge
VIE	Variable Interest Entity

Change in Basic Earnings Per Share From Prior Year First Quarter

Basic Earnings Per Share – First Quarter 2008	$ 0.91
Regulatory charges – 2009	(0.55)
Income tax resolution – 2009	0.04
Organizational restructuring – 2009	(0.05)
Gain on non-core asset sales – 2008	(0.06)
Trust securities impairment	(0.04)
Revenues	0.18
Fuel and purchased power	(0.24)
Amortization / deferral of regulatory assets	0.13
Other expenses	0.07
Basic Earnings Per Share – First Quarter 2009	$ 0.39

	Three Months			Nine Months
Change in Basic Earnings Per Share	Ended			Ended
From Prior Year Periods	September 30			September 30

Basic Earnings Per Share – 2007	$	1.36		$	3.39
Gain on non-core asset sales – 2008/2007		(0.04	)		0.02
Litigation settlement – 2008		-			0.03
Saxton decommissioning regulatory asset – 2007		-			(0.05	)
Trust securities impairment		(0.05	)		(0.09	)
Revenues		0.57			1.36
Fuel and purchased power		(0.34	)		(1.16	)
Depreciation and amortization		(0.02	)		(0.07	)
Deferral of new regulatory assets		(0.10	)		(0.23	)
Investment Income – decommissioning trusts and corporate-owned life insurance		0.04			(0.05	)
Income tax adjustments		0.12			0.12
Other expense reductions		0.01			0.02
Reduced common shares outstanding		-			0.03
Basic Earnings Per Share – 2008	$	1.55		$	3.32

	Three Months Ended September 30,							Nine Months Ended September 30,
						Increase							Increase
	2008		2007			(Decrease)		2008		2007			(Decrease)
	(In millions, except per share data)
Net Income
By Business Segment:
Energy delivery services	$	283	$	269		$	14	$	655	$	695		$	(40	)
Competitive energy services		164		148			16		317		388			(71	)
Ohio transitional generation services		19		16			3		62		69			(7	)
Other and reconciling adjustments*		5		(20	)		25		(24)		(111	)		87
Total	$	471	$	413		$	58	$	1,010	$	1,041		$	(31	)

Basic Earnings Per Share	$	1.55	$	1.36		$	0.19	$	3.32	$	3.39		$	(0.07	)
Diluted Earnings Per Share	$	1.54	$	1.34		$	0.20	$	3.29	$	3.35		$	(0.06	)

	Three Months
	Ended September 30,				Increase
Revenues by Type of Service	2008		2007		(Decrease)
	(In millions)
Distribution services	$	1,100	$	1,104	$	(4	)
Generation sales:
Retail		986		942		44
Wholesale		286		207		79
Total generation sales		1,272		1,149		123
Transmission		241		219		22
Other		44		48		(4	)
Total Revenues	$	2,657	$	2,520	$	137

Electric Distribution KWH Deliveries
Residential	~~(1.9)~~--	%
Commercial	~~(1.1)~~(4.1	) %
Industrial	~~(4.1)~~(17.5	) %
Total Distribution KWH Deliveries	~~(2.3)~~(6.7	) %

Sources of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 1.9 % decrease in sales volumes	$	(18	)
Change in prices		62
		44
Wholesale:
Effect of 2.4% decrease in sales volumes		(5	)
Change in prices		84
		79
Net Increase in Generation Revenues	$	123

~~Source of Change in Purchased Power~~	~~Increase~~ ~~(Decrease)~~
	~~(In millions)~~
~~Purchases from non-affiliates:~~
~~Change due to increased unit costs~~	$	~~146~~
~~Change due to decreased volumes~~		~~(45~~	)
		~~101~~
~~Purchases from FES:~~
~~Change due to decreased unit costs~~		(6	)
~~Change due to decreased volumes~~		~~(10~~	)
		~~(16~~	)

~~Decrease in NUG costs deferred~~		49
~~Net Increase in Purchased Power Costs~~	$	~~134~~

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	120
Change due to decreased volumes		(103	)
		17
Purchases from FES:
Change due to decreased unit costs		(9	)
Change due to increased volumes		22
		13

Increase in NUG costs deferred		(34	)
Net Decrease in Purchased Power Costs	$	(4	)

Source of Change in Retail Generation Revenues	Increase (Decrease)
	(In millions)
Effect of 3.1% decrease in sales volumes	$	(19	)
Change in prices		72
Total Increase in Retail Generation Revenues	$	53

~~Electric Distribution KWH Deliveries~~
~~Residential~~	~~(1.3)~~	%
~~Commercial~~	~~(0.5)~~	%
~~Industrial~~	~~(1.8)~~	%
~~Total Distribution KWH Deliveries~~	~~(1.2)~~	%

Source of Change in Generation Revenues	Increase
	(In millions)
Retail:
Effect of 1.4% decrease in sales volumes	$	(24	)
Change in prices		180
Total Increase in Retail Generation Revenues	$	156

	~~Aggregate LOC~~
	~~Amount(5)~~			~~Reimbursements of~~
~~LOC Bank~~	~~(In millions)~~		~~LOC Termination Date~~	~~LOC Draws Due~~
~~Barclays Bank(1)~~	$	~~149~~	~~June 2009~~	~~June 2009~~
~~Bank of America(1) (2)~~		~~101~~	~~June 2009~~	~~June 2009~~
~~The Bank of Nova Scotia(1)~~		~~255~~	~~Beginning June 2010~~	~~Shorter of 6 months or LOC termination date~~
~~The Royal Bank of Scotland(1)~~		~~131~~	~~June 2012~~	~~6 months~~
~~KeyBank(1) (3)~~		~~266~~	~~June 2010~~	~~6 months~~
~~Wachovia Bank~~		~~648~~	~~March 2009~~	~~March 2009~~
~~Barclays Bank(4)~~		~~528~~	~~Beginning December 2010~~	~~30 days~~
~~PNC Bank~~		70	~~Beginning December 2010~~	~~5 days~~
~~Total~~	$	~~2,148~~

Currently Payable Long-term Debt
		(In millions)
PCRBs supported by bank LOCs (1)	$	2,126
CEI FMBs (2)		125
CEI secured PCRBs (2)		82
Penelec unsecured notes (3)		100
NGC collateralized lease obligation bonds (4)		37
Sinking fund requirements (5)		39
	$	2,509

	Nine Months Ended
Securities Issued or	September 30,
Redeemed / Repurchased	2008		2007
	(In millions)
New issues
Pollution control notes	$	611	$	-
Unsecured notes		20		1,100
	$	631	$	1,100
Redemptions / Repurchases
First mortgage bonds	$	1	$	287
Pollution control notes		534		4
Senior secured notes		23		203
Unsecured notes		175		153
Common stock		-		918
	$	733	$	1,565

Summary of Cash Flows Provided from	Property
(Used for) Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Nine Months Ended September 30, 2008
Energy delivery services	$	(621	)	$	33		$	(3	)	$	(591	)
Competitive energy services(1)		(1,430	)		(13	)		(121	)		(1,564	)
Other(2)		(106	)		57			(54	)		(103	)
Inter-Segment reconciling items		(20	)		(12	)		-			(32	)
Total	$	(2,177	)	$	65		$	(178	)	$	(2,290	)

Nine Months Ended September 30, 2007
Energy delivery services	$	(609	)	$	6		$	(2	)	$	(605	)
Competitive energy services		(462	)		1,311			2			851
Other		(6	)		(4	)		1			(9	)
Inter-Segment reconciling items		(50	)		(15	)		-			(65	)
Total	$	(1,127	)	$	1,298		$	1		$	172

(1) Other investing activities include approximately $82 million in restricted funds to redeem outstanding debt in the fourth quarter of 2008. (2) Other investing activities include approximately $64 million in cash investments for the equity interest in Signal Peak.

	Three Months									Nine Months
Increase (Decrease) in the Fair Value	Ended September 30, 2008									Ended September 30, 2008
of 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	$	(616	)	$	(37	)	$	(653	)	$	(713	)	$	(26	)	$	(739	)
Additions/change in value of existing contracts		23			33			56			(10	)		9			(1	)
Settled contracts		18			(6	)		12			148			7			155
Outstanding net liability at end of period (1)		(575	)		(10	)		(585	)		(575	)		(10	)		(585	)

Non-commodity Net Assets at End of Period:
Interest rate swaps (2)		-			-			-			-			-			-
Net Liabilities - Derivative Contracts at End of Period	$	(575	)	$	(10	)	$	(585	)	$	(575	)	$	(10	)	$	(585	)

Impact of Changes in Commodity Derivative Contracts(3)
Income Statement effects (pre-tax)	$	(1	)	$	-		$	(1	)	$	-		$	-		$	-
Balance Sheet effects:
Other comprehensive income (pre-tax)	$	-		$	27		$	27		$	-		$	16		$	16
Regulatory assets (net)	$	(42	)	$	-		$	(42	)	$	(138	)	$	-		$	(138	)

Source of Information
- Fair Value by Contract Year	2008(1)		2009		2010		2011		2012		Thereafter		Total
	(In millions)
Prices actively quoted(2)	$	(2)	$	(5)	$	(1)	$	-	$	-	$	-	$	(8)
Other external sources(3)		(58)		(182)		(151)		(106)		-		-		(497)
Prices based on models		-		-		-		-		(32)		(48)		(80)
Total(4)	$	(60)	$	(187)	$	(152)	$	(106)	$	(32)	$	(48)	$	(585)

ARO Reconciliation	FirstEnergy			FES			OE			CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Balance, July 1, 2008	$	1,307		$	836		$	96		$	2	$	29	$	92	$	166	$	84
Liabilities incurred		5			-			-			-		-		-		-		-
Liabilities settled		(1	)		(1	)		-			-		-		-		-		-
Accretion		21			14			1			-		1		2		2		2
Revisions in estimated cash flows		(18	)		-			(18	)		-		-		-		-		-
Balance, September 30, 2008	$	1,314		$	849		$	79		$	2	$	30	$	94	$	168	$	86

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

	Maximum Exposure		Discounted Lease Payments, net		Net Exposure
	(in millions)
FES	$	1,363	$	1,209	$	154
OE	788		597		191
CEI	718		79		639
TE	718		421		297

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

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

REVENUES	$	1,222,783		$	574,394		$	267,017		$	(822,590	)	$	1,241,604

EXPENSES:
Fuel		8,177			307,646			34,123			-			349,946
Purchased power from non-affiliates		221,493			-			-			-			221,493
Purchased power from affiliates		815,243			7,347			15,821			(822,590	)		15,821
Other operating expenses		35,596			110,701			120,697			12,190			279,184
Provision for depreciation		1,978			33,432			30,559			(1,336	)		64,633
General taxes		4,829			10,768			6,139			-			21,736
Total expenses		1,087,316			469,894			207,339			(811,736	)		952,813
		-			-			-			-
OPERATING INCOME		135,467			104,500			59,678			(10,854	)		288,791

OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		102,777			(515	)		13,287			(97,122	)		18,427
Interest expense - affiliates		(120	)		(4,963	)		(2,932	)		-			(8,015	)
Interest expense - other		(8,464	)		(23,447	)		(17,183	)		16,325			(32,769	)
Capitalized interest		41			11,376			978			-			12,395
Total other income (expense)		94,234			(17,549	)		(5,850	)		(80,797	)		(9,962	)

INCOME BEFORE INCOME TAXES		229,701			86,951			53,828			(91,651	)		278,829

INCOME TAXES		44,046			31,863			14,995			2,270			93,174

NET INCOME	$	185,655		$	55,088		$	38,833		$	(93,921	)	$	185,655

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of September 30, 2008	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	-	$	-	$	-		$	2
Receivables-
Customers		137,126		-		-		-			137,126
Associated companies		267,777		195,005		100,481		(299,484	)		263,779
Other		910		1,595		20,419		-			22,924
Notes receivable from associated companies		118,526		38,400		-		-			156,926
Materials and supplies, at average cost		3,519		288,623		205,134		-			497,276
Prepayments and other		64,585		84,138		30,807		-			179,530
		592,445		607,761		356,841		(299,484	)		1,257,563

PROPERTY, PLANT AND EQUIPMENT:
In service		108,733		5,413,310		4,704,478		(391,859	)		9,834,662
Less - Accumulated provision for depreciation		10,990		2,712,638		1,658,863		(170,774	)		4,211,717
		97,743		2,700,672		3,045,615		(221,085	)		5,622,945
Construction work in progress		2,827		1,225,381		157,444		-			1,385,652
		100,570		3,926,053		3,203,059		(221,085	)		7,008,597
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,145,384		-			1,145,384
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		3,581,979		-		-		(3,581,979	)		-
Other		2,124		38,247		202		-			40,573
		3,584,103		38,247		1,208,486		(3,581,979	)		1,248,857
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		9,655		471,718		-		(251,032	)		230,341
Lease assignment receivable from associated companies		-		71,356		-		-			71,356
Goodwill		24,248		-		-		-			24,248
Property taxes		-		25,007		22,767		-			47,774
Pension assets		3,208		11,556		-		-			14,764
Unamortized sale and leaseback costs		-		8,445		-		48,920			57,365
Other		18,343		59,511		18,717		(46,869	)		49,702
		55,454		647,593		41,484		(248,981	)		495,550
	$	4,332,572	$	5,219,654	$	4,809,870	$	(4,351,529	)	$	10,010,567
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	4,679	$	873,562	$	1,077,289	$	(17,315	)	$	1,938,215
Short-term borrowings-
Associated companies		-		147,108		164,642		-			311,750
Other		1,000,000		-		-		-			1,000,000
Accounts payable-
Associated companies		276,155		202,678		158,215		(275,601	)		361,447
Other		36,724		126,449		-		-			163,173
Accrued taxes		4,109		88,826		17,661		(29,877	)		80,719
Other		36,491		116,637		26,777		38,009			217,914
		1,358,158		1,555,260		1,444,584		(284,784	)		4,073,218
CAPITALIZATION:
Common stockholder's equity		2,916,934		1,813,911		1,755,054		(3,568,965	)		2,916,934
Long-term debt and other long-term obligations		40,333		1,364,207		451,365		(1,296,982	)		558,923
		2,957,267		3,178,118		2,206,419		(4,865,947	)		3,475,857
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,035,013			1,035,013
Accumulated deferred income taxes		-		-		235,811		(235,811	)		-
Accumulated deferred investment tax credits		-		40,209		23,759		-			63,968
Asset retirement obligations		-		24,148		825,327		-			849,475
Retirement benefits		9,745		57,822		-		-			67,567
Property taxes		-		25,328		22,767		-			48,095
Lease market valuation liability		-		319,129		-		-			319,129
Other		7,402		19,640		51,203		-			78,245
		17,147		486,276		1,158,867		799,202			2,461,492
	$	4,332,572	$	5,219,654	$	4,809,870	$	(4,351,529	)	$	10,010,567

	Period
	July 1-31,	August 1-31,	September 1-30,	Third
	2008	2008	2008	Quarter
Total Number of Shares Purchased (a)	52,166	32,187	208,772	293,125
Average Price Paid per Share	$81.63	$71.63	$72.09	$73.74
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	-	-	-	-