UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549 ~~(Mark~~

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, ~~2002~~ 2008

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from

Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.

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

1-3522	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 ( )	Ohio Edison Company and Pennsylvania Electric Company
Yes ( ) No (X)	The Cleveland Electric Illuminating Company and The Toledo Edison Company

Large Accelerated Filer ( )	N/A
Accelerated Filer ( )	N/A
Non-accelerated Filer (Do not check if a smaller reporting company) (X)	Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company and Pennsylvania Electric Company

Smaller Reporting Company

( )

N/A

Yes ( ) No (X)

Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company and Pennsylvania Electric Company

	OUTSTANDING
CLASS	AS OF MAY 8, 2008
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
Pennsylvania Electric Company, $20 par value	4,427,577

OMISSION OF CERTAIN INFORMATION

·	the speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Ohio and Pennsylvania,

·	the impact of the PUCO’s rulemaking process on the Ohio Companies’ ESP and MRO filings,

·	economic or weather conditions affecting future sales and margins,

·	changes in markets for energy services,

·	changing energy and commodity market prices and availability,

·	replacement power costs being higher than anticipated or inadequately hedged,

·	the continued ability of FirstEnergy’s regulated utilities to collect transition and other charges or to recover increased transmission costs,

·	maintenance costs being higher than anticipated,

·	other legislative and regulatory changes, revised environmental requirements, including possible GHG emission regulations,

·	the impact of the U.S. Court of Appeals’ July 11, 2008 decision to vacate the CAIR rules and the scope of any laws, rules or regulations that may ultimately take their place,

the uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated) or levels of emission reductions related to the Consent Decree resolving the NSR litigation or other potential regulatory initiatives,

·	adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits and oversight) by the NRC (including, but not limited to, the Demand for Information issued to FENOC on May 14, 2007),

the timing and outcome of various proceedings before the PUCO (including, but not limited to, the ESP and MRO proceedings as well as the distribution rate cases and the generation supply plan filing for the Ohio Companies and the successful resolution of the issues remanded to the PUCO by the Ohio Supreme Court regarding the RSP and RCP, including the recovery of deferred fuel costs),

·	Met-Ed’s and Penelec’s transmission service charge filings with the PPUC as well as the resolution of the Petitions for Review filed with the Commonwealth Court of Pennsylvania with respect to the transition rate plan for Met-Ed and Penelec,

·	the continuing availability of generating units and their ability to operate at or near full capacity,

·	the ability to comply with applicable state and federal reliability standards,

·	the ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives),

·	the ability to improve electric commodity margins and to experience growth in the distribution business,

·	the changing market conditions that could affect the value of assets held in the registrants’ nuclear decommissioning trusts, pension trusts and other trust funds, and cause FirstEnergy to make additional contributions sooner, or in an amount that is larger than currently anticipated,

·	the ability to access the public securities and other capital and credit markets in accordance with FirstEnergy’s financing plan and the cost of such capital,

·	changes in general economic conditions affecting the registrants,

·	the state of the capital and credit markets affecting the registrants, and

·	the risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors.

The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on the registrants’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. Also, a security rating is not a recommendation to buy, sell or hold securities, and it may be subject to revision or withdrawal at any time and each such rating should be evaluated independently of any other rating. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events or otherwise.

		Pages
Glossary of Terms		ii-iv

Part I. Financial Information

Item 1. Financial Statements.		1

Ohio Edison Company

	Report of Independent Registered Public Accounting Firm	2
	Consolidated Statements of Income and Comprehensive Income	3
	Consolidated Balance Sheets	4
	Consolidated Statements of Cash Flows	5

The Cleveland Electric Illuminating Company

	Report of Independent Registered Public Accounting Firm	6
	Consolidated Statements of Income and Comprehensive Income	7
	Consolidated Balance Sheets	8
	Consolidated Statements of Cash Flows	9

The Toledo Edison Company

	Report of Independent Registered Public Accounting Firm	10
	Consolidated Statements of Income and Comprehensive Income	11
	Consolidated Balance Sheets	12
	Consolidated Statements of Cash Flows	13

Pennsylvania Electric Company

	Report of Independent Registered Public Accounting Firm	14
	Consolidated Statements of Income and Comprehensive Income	15
	Consolidated Balance Sheets	16
	Consolidated Statements of Cash Flows	17

Combined Notes to Consolidated Financial Statements		18-50

Item 4T. Controls and Procedures – OE, CEI, TE and Penelec.		51

Part II. Other Information

Item 6. Exhibits.		52

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
Companies	OE, CEI, TE, JCP&L, Met-Ed and Penelec
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial and other corporate support services
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
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
TEBSA	Termobarranquila S.A. Empresa de Servicios Publicos

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

AEP	American Electric Power Company, Inc.
AOCL	Accumulated Other Comprehensive Loss
AQC	Air Quality Control
ARB	Accounting Research Bulletin
ARO	Asset Retirement Obligation
ASM	Ancillary Services Market
BGS	Basic Generation Service
BPJ	Best Professional Judgment
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CBP	Competitive Bid Process
CO2	Carbon Dioxide
DFI	Demand for Information
DOJ	United States Department of Justice
DRA	Division of Ratepayer Advocate
EIS	Energy Independence Strategy
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"

GLOSSARY OF TERMS, Cont’d.

FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
FIN 48	FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109”
FirstCom	First Communications, Inc.
FMB	First Mortgage Bonds
FSP	FASB Staff Position
FSP FAS 157-2	FSP FAS 157-2, “Effective Date of FASB Statement No. 157”
FTR	Financial Transmission Rights
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
ICE	Intercontinental Exchange
IRS	Internal Revenue Service
ISO	Independent System Operator
kV	Kilovolt
KWH	Kilowatt-hours
LIBOR	London Interbank Offered Rate
LOC	Letter of Credit
MEIUG	Met-Ed Industrial Users Group
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
MRO	Market Rate Offer
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
NOPR	Notice of Proposed Rulemaking
NOV	Notice of Violation
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
NYMEX	New York Mercantile Exchange
OCA	Office of Consumer Advocate
OTC	Over the Counter
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
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
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Service
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
SFAS	Statement of Financial Accounting Standards
SFAS 109	SFAS No. 109, “Accounting for Income Taxes”
SFAS 123(R)	SFAS No. 123(R), "Share-Based Payment"
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”

GLOSSARY OF TERMS, Cont’d.

SFAS 141(R)	SFAS No 141(R), “Business Combinations”
SFAS 143	SFAS No. 143, “Accounting for Asset Retirement Obligations”
SFAS 157	SFAS No. 157, “Fair Value Measurements”
SFAS 159	SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”
SFAS 160	SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”
SFAS 161	SFAS No 161, “Disclosure about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”
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

ITEM 1. FINANCIAL STATEMENTS.

Report of Independent Registered Public Accounting Firm

PricewaterhouseCoopers LLP

Cleveland, Ohio

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

which is as of November 24, 2008.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2008			2007
	(In thousands)

REVENUES:
Electric sales	$	622,271		$	594,344
Excise tax collections		30,378			31,254
Total revenues		652,649			625,598

EXPENSES:
Fuel		3,170			3,015
Purchased power		340,186			349,852
Nuclear operating costs		43,021			41,514
Other operating costs		94,135			88,486
Provision for depreciation		21,493			18,848
Amortization of regulatory assets		48,538			45,417
Deferral of new regulatory assets		(25,411	)		(36,649	)
General taxes		50,453			49,745
Total expenses		575,585			560,228

OPERATING INCOME		77,064			65,370

OTHER INCOME (EXPENSE):
Investment income		15,055			26,630
Miscellaneous income (expense)		(3,806	)		373
Interest expense		(17,641	)		(21,022	)
Capitalized interest		110			110
Total other income (expense)		(6,282	)		6,091

INCOME BEFORE INCOME TAXES		70,782			71,461

INCOME TAXES		26,873			17,426

NET INCOME		43,909			54,035

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(3,994	)		(3,423	)
Change in unrealized gain on available-for-sale securities		(7,571	)		(126	)
Other comprehensive loss		(11,565	)		(3,549	)
Income tax benefit related to other comprehensive loss		(4,262	)		(1,503	)
Other comprehensive loss, net of tax		(7,303	)		(2,046	)

TOTAL COMPREHENSIVE INCOME	$	36,606		$	51,989

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

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,		December 31,
	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	732	$	732
Receivables-
Customers (less accumulated provisions of $7,870,000 and $8,032,000,
respectively, for uncollectible accounts)		266,360		248,990
Associated companies		179,875		185,437
Other (less accumulated provisions of $5,638,000 and $5,639,000,
respectively, for uncollectible accounts)		16,474		12,395
Notes receivable from associated companies		589,790		595,859
Prepayments and other		17,785		10,341
		1,071,016		1,053,754
UTILITY PLANT:
In service		2,804,505		2,769,880
Less - Accumulated provision for depreciation		1,106,174		1,090,862
		1,698,331		1,679,018
Construction work in progress		60,617		50,061
		1,758,948		1,729,079
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		258,405		258,870
Investment in lease obligation bonds		253,747		253,894
Nuclear plant decommissioning trusts		119,948		127,252
Other		33,014		36,037
		665,114		676,053
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		709,969		737,326
Pension assets		235,933		228,518
Property taxes		65,520		65,520
Unamortized sale and leaseback costs		43,882		45,133
Other		44,640		48,075
		1,099,944		1,124,572
	$	4,595,022	$	4,583,458
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	334,656	$	333,224
Short-term borrowings-
Associated companies		50,692		50,692
Other		2,609		2,609
Accounts payable-
Associated companies		155,654		174,088
Other		19,376		19,881
Accrued taxes		93,390		89,571
Accrued interest		16,459		22,378
Other		99,532		65,163
		772,368		757,606
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 shares outstanding		1,220,368		1,220,512
Accumulated other comprehensive income		41,083		48,386
Retained earnings		351,186		307,277
Total common stockholder's equity		1,612,637		1,576,175
Long-term debt and other long-term obligations		839,107		840,591
		2,451,744		2,416,766
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		783,777		781,012
Accumulated deferred investment tax credits		15,990		16,964
Asset retirement obligations		95,009		93,571
Retirement benefits		176,597		178,343
Deferred revenues - electric service programs		36,821		46,849
Other		262,716		292,347
		1,370,910		1,409,086
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	4,595,022	$	4,583,458

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

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended March 31,
	Restated
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	43,909		$	54,035
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		21,493			18,848
Amortization of regulatory assets		48,538			45,417
Deferral of new regulatory assets		(25,411	)		(36,649	)
Amortization of lease costs		32,934			32,934
Deferred income taxes and investment tax credits, net		6,866			(3,992	)
Accrued compensation and retirement benefits		(19,482	)		(16,794	)
Pension trust contribution		-			(20,261	)
Increase in operating assets-
Receivables		(27,496	)		(102,469	)
Prepayments and other current assets		(7,451	)		(6,339	)
Increase (decrease) in operating liabilities-
Accounts payable		(3,939	)		42,095
Accrued taxes		2,991			(46,791	)
Accrued interest		(5,919	)		(6,812	)
Electric service prepayment programs		(10,028	)		(9,053	)
Other		(2,066	)		(3,283	)
Net cash provided from (used for) operating activities		54,939			(59,114	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		-			77,473
Redemptions and Repayments-
Common stock		-			(500,000	)
Long-term debt		(80	)		(72	)
Dividend Payments-
Common stock		(15,000	)		-
Net cash used for financing activities		(15,080	)		(422,599	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(49,011	)		(29,888	)
Sales of investment securities held in trusts		62,344			12,951
Purchases of investment securities held in trusts		(63,797	)		(13,805	)
Loan repayments from associated companies, net		6,534			511,082
Cash investments		147			168
Other		3,924			1,187
Net cash provided from (used for) investing activities		(39,859	)		481,695

Net change in cash and cash equivalents		-			(18	)
Cash and cash equivalents at beginning of period		732			712
Cash and cash equivalents at end of period	$	732		$	694

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

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of Directors of

PricewaterhouseCoopers LLP

Cleveland, Ohio

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

which is as of November 24, 2008.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2008			2007
	(In thousands)

REVENUES:
Electric sales	$	418,708		$	422,805
Excise tax collections		18,600			18,027
Total revenues		437,308			440,832

EXPENSES:
Fuel		-			13,191
Purchased power		193,244			180,657
Other operating costs		65,118			74,951
Provision for depreciation		19,076			18,468
Amortization of regulatory assets		38,256			33,129
Deferral of new regulatory assets		(29,248	)		(33,957	)
General taxes		40,083			38,894
Total expenses		326,529			325,333

OPERATING INCOME		110,779			115,499

OTHER INCOME (EXPENSE):
Investment income		9,188			17,687
Miscellaneous income		534			731
Interest expense		(32,520	)		(35,740	)
Capitalized interest		196			205
Total other expense		(22,602	)		(17,117	)

INCOME BEFORE INCOME TAXES		88,177			98,382

INCOME TAXES		30,326			34,833

NET INCOME		57,851			63,549

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(213	)		1,202
Income tax expense related to other comprehensive income		281			355
Other comprehensive income (loss), net of tax		(494	)		847

TOTAL COMPREHENSIVE INCOME	$	57,357		$	64,396

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

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	241		$	232
Receivables-
Customers (less accumulated provisions of $7,224,000 and $7,540,000,		266,701			251,000
respectively, for uncollectible accounts)
Associated companies		70,727			166,587
Other		3,643			12,184
Notes receivable from associated companies		54,679			52,306
Prepayments and other		1,728			2,327
		397,719			484,636
UTILITY PLANT:
In service		2,142,458			2,256,956
Less - Accumulated provision for depreciation		827,160			872,801
		1,315,298			1,384,155
Construction work in progress		40,834			41,163
		1,356,132			1,425,318
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		425,722			463,431
Other		10,275			10,285
		435,997			473,716
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,688,521			1,688,521
Regulatory assets		853,716			870,695
Pension assets		64,497			62,471
Property taxes		76,000			76,000
Other		32,735			32,987
		2,715,469			2,730,674
	$	4,905,317		$	5,114,344
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	207,281		$	207,266
Short-term borrowings-
Associated companies		365,816			531,943
Accounts payable-
Associated companies		139,423			169,187
Other		6,169			5,295
Accrued taxes		118,102			94,991
Accrued interest		37,726			13,895
Other		35,044			34,350
		909,561			1,056,927
CAPITALIZATION:
Common stockholder's equity
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding		873,353			873,536
Accumulated other comprehensive loss		(69,623	)		(69,129	)
Retained earnings		743,278			685,428
Total common stockholder's equity		1,547,008			1,489,835
Long-term debt and other long-term obligations		1,447,980			1,459,939
		2,994,988			2,949,774
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		719,938			725,523
Accumulated deferred investment tax credits		18,102			18,567
Retirement benefits		94,322			93,456
Deferred revenues - electric service programs		21,297			27,145
Lease assignment payable to associated companies		38,420			131,773
Other		108,689			111,179
		1,000,768			1,107,643
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	4,905,317		$	5,114,344

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

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31,
	Restated
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	57,851		$	63,549
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		19,076			18,468
Amortization of regulatory assets		38,256			33,129
Deferral of new regulatory assets		(29,248	)		(33,957	)
Deferred rents and lease market valuation liability		-			(46,528	)
Deferred income taxes and investment tax credits, net		(4,965	)		(5,453	)
Accrued compensation and retirement benefits		(3,507	)		(890	)
Pension trust contribution		-			(24,800	)
Decrease in operating assets-
Receivables		90,280			224,011
Prepayments and other current assets		604			592
Increase (decrease) in operating liabilities-
Accounts payable		1,111			(256,808	)
Accrued taxes		23,196			13,959
Accrued interest		23,831			18,122
Electric service prepayment programs		(5,847	)		(5,313	)
Other		(63	)		(167	)
Net cash provided from (used for) operating activities		210,575			(2,086	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			247,715
Redemptions and Repayments-
Long-term debt		(165	)		(150	)
Short-term borrowings, net		(177,960	)		(130,585	)
Dividend Payments-
Common stock		(30,000	)		(24,000	)
Net cash provided from (used for) financing activities		(208,125	)		92,980

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(37,203	)		(36,682	)
Loans to associated companies, net		(2,373	)		(231,907	)
Collection of principal on long-term notes receivable		-			133,341
Redemptions of lessor notes		37,709			35,614
Other		(574	)		9,294
Net cash used for investing activities		(2,441	)		(90,340	)

Net increase in cash and cash equivalents		9			554
Cash and cash equivalents at beginning of period		232			221
Cash and cash equivalents at end of period	$	241		$	775

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

Report of Independent Registered Public Accounting Firm

PricewaterhouseCoopers LLP

Cleveland, Ohio

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

which is as of November 24, 2008.

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2008			2007
	(In thousands)

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

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

OPERATING INCOME		26,134			40,252

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

INCOME BEFORE INCOME TAXES		25,103			36,957

INCOME TAXES		8,088			11,097

NET INCOME		17,015			25,860

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

TOTAL COMPREHENSIVE INCOME	$	18,185		$	26,478

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

THE TOLEDO EDISON COMPANY

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

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

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

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

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

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

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

Report of Independent Registered Public Accounting Firm

PricewaterhouseCoopers LLP

Cleveland, Ohio

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

which is as of November 24, 2008.

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

		2008			2007

	(In thousands)

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

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

OPERATING INCOME			55,990			65,669

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

INCOME BEFORE INCOME TAXES			39,671			56,007

INCOME TAXES			18,279			24,263

NET INCOME			21,392			31,744

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

TOTAL COMPREHENSIVE INCOME		$	19,452		$	30,230

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

PENNSYLVANIA ELECTRIC COMPANY

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

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

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

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

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

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

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

The consolidated financial statements as of March 31, 2008 and for the three-month periods ended March 31, 2008 and 2007 have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated May 7, 2008, except as to the error correction described in Note 1, which is as of November 24, 2008) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities ~~Met-Ed~~Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.

Restatement of the Consolidated Statements of Cash Flows

The effects of the ~~respective Met-Ed~~corrections on OE’s, CEI’s, TE’s and ~~Penelec trusts is through separate wholly-owned limited partnerships,~~Penelec’s Consolidated Statements of ~~which a wholly-owned subsidiary of each company is~~Cash Flows for the ~~sole general partner. In these transactions, the sole assets and sources of revenues of each trust~~three months ended March 31, 2008 are the preferred securities of the applicable limited partnership, whose sole assets are in the 7.35% and 7.34% subordinated debentures (aggregate principal amount of $103.1 million each) of Met-Ed and Penelec, respectively. In each case, the applicable parent company has effectively provided a full and unconditional guarantee of its obligations under its trust's preferred securities. 1 ~~Derivative Accounting On January 1, 2001, FirstEnergy adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities",~~ as amended by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities -- an amendment of FASB Statement No. 133". The cumulative effect to January 1, 2001 was a charge of $8.5 million (net of $5.8 million of income taxes) or $.03follows:

OE

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

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

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

Net change in cash and cash equivalents	$	-		$	-

CEI

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

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

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

Net increase in cash and cash equivalents	$	9		$	9

TE

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

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

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

Net increase in cash and cash equivalents	$	191		$	191

PENELEC

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

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

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

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

2. EARNINGS PER SHARE

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

Reconciliation of Basic and Diluted		Three Months Ended March 31,
Earnings per Share of Common Stock		2008		2007
	(In millions, except per share amounts)
Net income		$	276	$	290

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

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

3. DIVESTITURES AND DISCONTINUED OPERATIONS

On March 7, 2008, FirstEnergy sold certain telecommunication assets, resulting in a net after-tax gain of $19.3 million. As a result of the sale, FirstEnergy adjusted goodwill by $1 million for the former GPU companies due to the realization of tax benefits that had been reserved in purchase accounting. The sale of assets did not meet the criteria for classification as discontinued operations as of March 31, 2008.

4. FAIR VALUE MEASURES

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

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

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

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

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

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

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

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

Liabilities:
Derivatives	$	-	$	98	$	-	$	98
NUG contracts(3)		-		-		682		682
Total	$	-	$	98	$	682	$	780

(1)

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

(2)

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

(3)

NUG contracts are completely offset by regulatory assets.

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

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

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

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

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

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

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

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

5. DERIVATIVE INSTRUMENTS

FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for electricity, natural gas, coal and ~~coal.~~energy transmission. 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, and to a lesser extent, for trading~~ purposes. FirstEnergy's Risk Policy Committee, comprised of ~~executive officers, exercises an independent~~members of senior management, provides general management oversight for risk ~~oversight function to ensure~~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 ~~prudent~~established risk management practices.

FirstEnergy ~~uses derivatives~~accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchases and normal sales criteria. Derivatives that meet those criteria are accounted for at cost. The changes in the fair value of derivative instruments that do not meet the normal purchases and normal sales criteria are recorded as other expense, as AOCL, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness. FirstEnergy does not offset fair value for the right to ~~hedge~~reclaim collateral or the ~~risk of price, interest rate and foreign currency fluctuations. FirstEnergy's primary ongoing hedging activity involves~~obligation to return collateral.

FirstEnergy hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas ~~purchases.~~purchases and anticipated interest payments associated with future debt issues. The ~~maximum periods over which the variability~~effective portion of ~~electricity~~such hedges are initially recorded in equity as other comprehensive income or loss and ~~natural gas cash flows~~ are ~~hedged are two and three years, respectively. Gains and losses from hedges of commodity price risks are~~subsequently included in net income ~~when~~as the underlying hedged commodities are ~~delivered.~~ delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings.

The ~~current~~ net deferred ~~loss~~losses of ~~$133.6~~$84 million included in ~~Accumulated Other Comprehensive Loss (AOCL)~~AOCL as of March 31, ~~2002,~~2008, for derivative hedging activity, as compared to ~~the~~$75 million as of December 31, ~~2001 balance of $169.4 million in AOCL,~~2007, resulted from a ~~$18.9~~net $21 million increase related to current hedging activity and a ~~$16.9~~$12 million ~~increase~~decrease due to net hedge losses ~~included in~~reclassified to earnings during the ~~quarter. Approximately $7.1~~three months ended March 31, 2008. Based on current estimates, approximately $19 million (after tax) of the ~~current~~ net deferred ~~loss~~losses on derivative instruments in AOCL isas of March 31, 2008 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. ~~However, the~~The fair value of these derivative instruments ~~will~~ fluctuate from period to period based on various market ~~factors~~factors.

FirstEnergy has entered into swaps that have been designated as fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. As of March 31, 2008, FirstEnergy had interest rate swaps with an aggregate notional value of $250 million and a fair value of $5 million.

During 2007 and the first three 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. During the first three months of 2008, FirstEnergy terminated swaps with a notional value of $300 million and entered into swaps with a notional value of $500 million. FirstEnergy paid $18 million related to the terminations, $1 million of which was deemed ineffective and recognized in current period earnings. FirstEnergy will ~~generally~~recognize the remaining $17 million loss over the life of the associated future debt. As of March 31, 2008, FirstEnergy had forward swaps with an aggregate notional amount of $600 million and a fair value of $(8) million.

6. ASSET RETIREMENT OBLIGATIONS

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

The ARO liability of $1.3 billion as of March 31, 2008 is primarily related to the future nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

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

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

ARO Reconciliation	FirstEnergy		FES		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Balance, January 1, 2008	$	1,267	$	810	$	94	$	2	$	28	$	90	$	161	$	82
Liabilities incurred		-		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-		-
Accretion		20		14		1		-		1		1		2		1
Revisions in estimated cash flows		-		-		-		-		-		-		-		-
Balance, March 31, 2008	$	1,287	$	824	$	95	$	2	$	29	$	91	$	163	$	83

Balance, January 1, 2007	$	1,190	$	760	$	88	$	2	$	27	$	84	$	151	$	77
Liabilities incurred		-		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-		-
Accretion		18		12		1		-		-		2		2		1
Revisions in estimated cash flows		-		-		-		-		-		-		-		-
Balance, March 31, 2007	$	1,208	$	772	$	89	$	2	$	27	$	86	$	153	$	78

7. PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees and those of its subsidiaries. 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. 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.

The components of FirstEnergy's net periodic pension cost and other postretirement benefit cost (including amounts capitalized) for the three months ended March 31, 2008 and 2007, consisted of the following:

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

Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net periodic pension costs and net periodic postretirement benefit costs (including amounts capitalized) recognized by each of the Companies for the three months ended March 31, 2008 and 2007 were as follows:

	Pension Benefit Cost (Credit)						Other Postretirement Benefit Cost (Credit)
	2008			2007			2008			2007
	(In millions)
FES	$	4		$	-		$	(2	)	$	-
OE		(7	)		(4	)		(2	)		(3	)
CEI		(1	)		-			1			1
TE		(1	)		-			1			1
JCP&L		(4	)		(2	)		(4	)		(4	)
Met-Ed		(3	)		(2	)		(3	)		(2	)
Penelec		(3	)		(3	)		(3	)		(3	)
Other FirstEnergy subsidiaries		(4	)		3			(3	)		(6	)
	$	(19	)	$	(8	)	$	(15	)	$	(16	)

8. VARIABLE INTEREST ENTITIES

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

Trusts

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

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

Loss Contingencies

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

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

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

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

Power Purchase Agreements

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

FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. As required by FIN 46R, FirstEnergy periodically requests from these eight entities the information necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the ~~margin on related sales and revenues.~~requested entity to be proprietary. As such, FirstEnergy ~~engages~~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 ~~trading of commodity derivatives and periodically experiences net open positions. FirstEnergy's risk management policies limit the~~NUG entities, its maximum exposure to ~~market risk~~loss relates primarily to the above-market costs it may incur for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs from these entities during the three months ended March 31, 2008 and 2007 are shown in the following table:

	Three Months Ended
	March 31,
	2008		2007
	(In millions)
JCP&L	$	19	$	20
Met-Ed		16		15
Penelec		8		8
	$	43	$	43

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 March 31, 2008, $391 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.

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

9. INCOME TAXES

On January 1, 2007, FirstEnergy adopted FIN 48, which provides guidance for accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. This interpretation prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. FIN 48 also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure 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.

As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits was $268 million. FirstEnergy recorded a $2.7 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate upon recognition. The majority of items that would not have affected the effective tax rate would be purchase accounting adjustments to goodwill upon recognition. During the first three months of 2008 and 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of March 31, 2008, FirstEnergy expects that it is reasonably possible that $8 million of the unrecognized benefits will be resolved within the next twelve months and is included in the caption “accrued taxes,” with the remaining $263 million included in the caption “other non-current liabilities” on the Consolidated Balance Sheets.

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

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open ~~positions~~from 2001-2007. The IRS began reviewing returns for the years 2001-2003 in July 2004 and ~~require daily reporting~~several items are under appeal. The federal audits for the years 2004-2006 are expected to close before December 2008, but management anticipates certain items to be under appeal. The IRS began auditing the year 2007 in February 2007 and year 2008 in February 2008 under its Compliance Assurance Process experimental program. Neither audit is expected to close before December 2008. Management believes that adequate reserves have been recognized and final settlement of ~~potential~~these audits is not expected to have a material adverse effect on FirstEnergy’s financial ~~exposures. 2 -~~condition or results of operations.

10. COMMITMENTS, GUARANTEES AND ~~CONTINGENCIES: Capital Expenditures FirstEnergy's current forecast reflects expenditures~~CONTINGENCIES

(A) GUARANTEES AND OTHER ASSURANCES

As part of approximately $3.2 billion (OE-$195 million, CEI-$256 million, TE-$129 million, Penn-$45 million, JCP&L-$572 million, Met-Ed-$336 million, Penelec-$387 million, ATSI-$118 million, FES-$814 millionnormal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of March 31, 2008, outstanding guarantees and other ~~subsidiaries-$309 million)~~assurances aggregated approximately $4.4 billion, consisting of parental guarantees - $0.9 billion, subsidiaries’ guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $0.7 billion.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, ~~additions~~plant and ~~improvements from 2002-2006,~~equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of which approximately $863 million (OE-$39 million, CEI-$57 million, TE-$27 million, Penn-$9 million, JCP&L-$144 million, Met-Ed-$79 million, Penelec-$84 million, ATSI-$20 million, FES-$261 millionthose subsidiaries directly involved in energy and ~~other subsidiaries-$143 million) is applicable~~energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to ~~2002. Investments for additional nuclear fuel during~~exceed the ~~2002-2006 period are estimated~~ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be ~~approximately $502~~satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4 billion (included in the $0.9 billion discussed above) as of March 31, 2008 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of March 31, 2008, FirstEnergy's maximum exposure under these collateral provisions was $440 million.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $66 million ~~(OE-$136~~provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $2 million ~~CEI-$166~~(subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($19 million ~~TE-$113 million~~as of March 31, 2008), which is renewable and ~~Penn-$87 million),~~declines yearly based upon the senior outstanding debt of ~~which approximately $35 million (OE-$10 million, CEI-$12 million, TE-$8 million~~TEBSA.

In July 2007, FGCO completed a sale and ~~Penn-$5 million) applies to 2002. Environmental Matters~~ leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.

(B)	ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate ~~the Companies~~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 ~~additional~~ capital expenditures for environmental compliance of approximately ~~$235 million, which~~$1.4 billion for the period 2008-2012.

FirstEnergy accrues environmental liabilities only when it concludes that it is ~~included~~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 ~~construction forecast provided under "Capital Expenditures" for 2002 through 2006. The Companies are~~period that they become both probable and reasonably estimable.

Clean Air Act Compliance

FirstEnergy is required to meet ~~federally approved sulfur dioxide (SO2)~~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 ~~$27,500~~$32,500 for each day the unit is in violation. The ~~Environmental Protection Agency (EPA)~~EPA has an interim enforcement policy for ~~SO2~~SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. ~~The Companies~~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 ~~Companies believe they are in~~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 ~~current SO2~~rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and ~~nitrogen oxides (NOx)~~a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.

FirstEnergy complies with SO2 reduction requirements under the Clean Air Act Amendments of ~~1990. SO2 reductions are being achieved~~1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. ~~NOx~~NOX reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional ~~NOx~~NOX reductions ~~from the Companies' Ohio and Pennsylvania~~at FirstEnergy's facilities. The EPA's ~~NOx~~NOX Transport Rule imposes uniform reductions of ~~NOx~~NOX emissions (an approximate 85% reduction in utility plant ~~NOx~~NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia 2 ~~including New Jersey, Ohio and Pennsylvania,~~ based on a conclusion that such ~~NOx~~NOX emissions are contributing significantly to ozone ~~pollution~~levels in the eastern United States. ~~State Implementation Plans (SIP) must comply by May 31, 2004~~FirstEnergy believes its facilities are also complying with ~~individual state NOx~~the NOX budgets established byunder SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the ~~EPA.~~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 ~~submitted a SIP that requires~~Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the ~~NOx budgets~~applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim.

On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the ~~Companies' Pennsylvania facilities~~Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by ~~May 1, 2003~~excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and ~~Ohio submitted~~ a ~~"draft" SIP~~stipulation in which the parties agreed that ~~requires compliance with~~GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the ~~NOx budgets at~~Court. Although it remains liable for civil or criminal penalties and fines that may be assessed relating to events prior to the ~~Companies' Ohio facilities~~sale of the Portland Station in 1999, Met-Ed is indemnified by ~~May 31, 2004. In July 1997,~~Sithe Energy against any other liability arising under the ~~EPA promulgated changes in the~~ CAA whether it arises out of pre-1999 or post-1999 events.

National Ambient Air Quality ~~Standard (NAAQS) for ozone~~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 ~~proposed a new~~the District of Columbia significantly contribute to non-attainment of the NAAQS for ~~previously unregulated ultra-fine particulate matter. In May 1999,~~fine particles and/or the ~~U.S.~~"8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2). FirstEnergy's Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO2 and NOX emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on NOX emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOX emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOX cap of 1.3 million tons annually. CAIR has been challenged in the United States Court of Appeals for the D.C. Circuit found constitutional and other defects in the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating ultra-fine particulates but found defects in the new NAAQS rules for ozone and decided that the EPA must revise those rules.District of Columbia. The future cost of compliance with these regulations may be substantial and ~~will~~may depend if and how they are ultimately implemented by the states in which the Companies operate affected facilities. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. Although unable to predict the outcome of ~~these proceedings, FirstEnergy believes the Sammis Plant~~this litigation and how CAIR is in full compliance with the Clean Air Act and the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. ultimately implemented.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power ~~plants. The EPA identified~~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 ~~established a schedule~~must now seek further judicial review of that ruling or take regulatory action to ~~propose regulations by December 2003 and issue final regulations by December 2004. The~~promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with ~~these~~mercury regulations may be ~~substantial.~~ substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

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

W. H. Sammis Plant

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

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

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

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

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

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities.

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

Clean Water Act

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

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

Regulation of Hazardous Waste

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA ~~has issued its final regulatory determination~~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 ~~nonhazardous~~non-hazardous waste. ~~Various environmental liabilities have been recognized on the Consolidated Balance Sheet as~~

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, ~~2002, based on estimates~~2008, FirstEnergy had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the ~~total costs~~application to the NRC to transfer the ownership of ~~cleanup,~~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 ~~Companies' proportionate responsibility~~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 ~~such costs and~~TMI-1 as it relates to the ~~financial ability~~timing of ~~other nonaffiliated entities to pay.~~ the decommissioning of TMI-2) seeks for these facilities.

The Companies have been named as ~~"potentially responsible parties" (PRPs)~~PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to ~~dispute. Federal~~dispute; however, federal law provides that all PRPs for a particular site may be ~~held~~ liable on a joint and several basis. ~~In addition,~~Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $92 million (JCP&L - $65 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through March 31, 2008. Included in the total for JCP&L ~~has~~are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants in New Jersey; ~~those costs~~which are being recovered by JCP&L through a non-bypassable ~~societal benefits charge.~~SBC.

Power Outages and Related Litigation

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The ~~Companies have total~~Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge is scheduled for June 13, 2008. FirstEnergy is defending this class action but is unable to predict the outcome of this matter. No liability has been accrued ~~liabilities aggregating approximately $58.2 million (JCP&L-$50.3 million, CEI-$2.9 million, TE-$0.2 million, Met-Ed-$0.2 million, Penelec-$0.9 million and other-$3.7 million)~~ as of March 31, ~~2002.~~2008.

Nuclear Plant Matters

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

Other Legal Matters

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

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

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

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

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

11. REGULATORY MATTERS

(A) RELIABILITY INITIATIVES

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

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

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

FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could have a material adverse effect on its financial condition, cash flows or results of operations. 3 - PENDING DIVESTITURES: FirstEnergy identified certain former GPU international operations for divestiture within twelve months of the merger date. These operations constitute individual "lines of business" as defined in Accounting Principles Board Opinion (APB) No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," with physically and operationally separable activities. Application of Emerging Issues Task Force (EITF) Issue No. 87-11, "Allocation of Purchase Price to Assets to Be Sold," required that expected, pre-sale cash flows, including incremental interest costs on related acquisition debt, of these operations be considered part of the purchase price allocation. Accordingly, subsequent to the merger date, results of operations and ~~incremental~~cash flows.

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

(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, with alternative options for the recovery period ranging from five to twenty-five years. This second application is currently pending before the PUCO and a hearing has been set for July 15, 2008.

The Ohio Companies filed an application and rate request for an increase in electric distribution rates with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the average electric bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operation and maintenance expenses and recovery of regulatory assets that were authorized in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of their investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. This amount excludes the recovery of deferred fuel costs, whose recovery is now being sought in a separate proceeding before the PUCO, discussed above. On January 3, 2008, the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings, the PUCO Staff submitted testimony decreasing their recommended revenue increase to a range of $114 million to $132 million. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $45 million of interest costs ~~related~~deferred through March 31, 2008 ($0.09 per share of common stock). The PUCO is expected to ~~these international subsidiaries were~~render its decision during the second or third quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing retail generation service to customers who do not ~~included in FirstEnergy's Consolidated Statements~~purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of ~~Income. Additionally, assets and liabilities of these international operations were segregated under separate captions in~~multiple bidding sessions conducted at different times during the ~~Consolidated Balance Sheet as "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale." 3~~ ~~In October 2001, FirstEnergy and Aquila, Inc. (formerly UtiliCorp United) announced that Aquila made~~year. The final price per KWH would reflect an offer to FirstEnergy to purchase Avon Energy Partners Holdings, FirstEnergy's wholly owned holding company of Midlands Electricity plc, for $2.1 billion including the assumption of $1.7 billion of debt. FirstEnergy accepted the offer upon completion of its merger with GPU and regulatory approvals for the transaction were received by Aquila. On March 18, 2002, FirstEnergy announced that the termsaverage of the ~~initial offer~~prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by ~~Aquila were modified such that Aquila~~customer class or a “slice-of-system” approach. A slice-of-system approach would ~~now acquire~~require the successful bidder to be responsible for supplying a ~~79.9 percent interest in Avon for approximately $1.9 billion (including the assumption of $1.7 billion of debt). FirstEnergy and Aquila together will own all~~fixed percentage of the ~~outstanding shares of Avon through a jointly owned subsidiary,~~utility’s total load notwithstanding the customer’s classification. The proposal provides the PUCO with each company having a 50-percent voting interest. The transaction closed on May 8, 2002. In accordance with applicable accounting guidance, the earnings of those foreign operations were capitalizedan option to phase in advance of the sale and not recognized in current earnings from the date of the GPU acquisition until February 6, 2002. However, the revision to the initial offer by Aquila caused a reversal of this accounting in the first quarter of 2002, resulting in the recognition of a cumulative effect ofgeneration price increases for residential tariff groups who would experience a change in ~~accounting~~their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Initial and reply comments on the proposal were filed by various parties in September and October 2007, respectively. The proposal is currently pending before the PUCO.

On April 22, 2008, an amended version of Substitute SB221 was passed by the Ohio House of Representatives and sent back to the Ohio Senate for concurrence. On April 23, 2008, the Ohio Senate approved the House's amendments to Substitute SB221 and forwarded the bill to the Governor for signature, which ~~increased net income by $31.7 million. This resulted from~~he signed on May 1, 2008. Amended Substitute SB221 requires all electric distribution utilities to file an RSP, now called an ESP, with the ~~application~~PUCO. An ESP is required to contain a proposal for the supply and pricing of ~~guidance provided by EITF Issue No. 90-6, "Accounting for Certain Events Not Addressed~~retail generation and may include proposals, without limitation, related to one or more of the following:

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

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

·	costs of an electric generating facility;

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

·	accounting for deferrals related to stabilizing retail electric service;

·	automatic increases or decreases in standard service offer price;

·	phase-in and securitization;

·	transmission service and related costs;

·	distribution service and related costs; and

·	economic development and energy efficiency.

A utility could also simultaneously file an MRO in ~~Issue No. 87-11 relating~~which it would have to an Acquired Operating Unit to Be Sold," accounting under EITF Issue No. 87-11, recognizing the net income of Avon from November 7, 2001 to February 6, 2002 that previously was not recognized by FirstEnergy in its consolidated earnings as discussed above. In addition, Avon's financial statements are no longer presented as "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale" in FirstEnergy's Consolidated Balance Sheet at March 31, 2002. 4 - REGULATORY MATTERS: In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation includeddemonstrate the following objective market criteria: The utility or its transmission service affiliate belongs to a FERC-approved RTO having a market-monitor function and the ability to mitigate market power, and a published source exists that identifies information for traded electricity and energy products that are contracted for delivery two years into the future. The PUCO would test the ESP and its pricing and all other terms and conditions against the MRO and may only approve the ESP if it is found to be more favorable to customers. As part of an ESP with a plan period longer than three years, the PUCO shall prospectively determine every fourth year of the plan whether it is substantially likely the plan will provide the electric distribution utility a return on common equity significantly in excess of the return likely to be earned by publicly traded companies, including utilities, that face comparable business and financial risk (comparable companies). If so, the PUCO may terminate the ESP. Annually under an ESP, the PUCO shall determine whether an electric distribution utility's earned return on common equity is significantly in excess of returns earned on common equity during the same period by comparable companies, and if so, shall require the utility to return such excess to customers by prospective adjustments. Amended Substitute SB221 also includes provisions ~~which are reflected~~dealing with advanced and renewable energy standards that contemplate 25% of electrical usage from these sources by 2025. Energy efficiency measures in the ~~Companies' respective state regulatory plans: o Allowing~~bill require energy savings in excess of 22% by 2025. Requirements are in place to meet annual benchmarks for renewable energy resources and energy efficiency, subject to review by the ~~Companies' electric customers~~PUCO. FirstEnergy is currently evaluating this legislation and expects to ~~select their generation suppliers; o establishing provider of last resort (PLR) obligations to non- shopping customers~~file an ESP in the ~~Companies' service areas; o allowing recovery~~second or third quarter of potentially stranded investment (or transition costs); o itemizing (unbundling) the current price of electricity into its component elements - including generation, transmission, distribution distribution and stranded costs recovery charges; o deregulating the Companies' electric generation businesses; and o continuing regulation of the Companies' transmission and distribution systems. Pennsylvania The Pennsylvania Public Utility Commission (PPUC) authorized 1998 rate restructuring plans for Penn, 2008.

Met-Ed and ~~Penelec. In 2000, the PPUC disallowed~~Penelec purchase a portion of ~~the requested additional stranded costs above those amounts granted in Met-Ed's~~their PLR and ~~Penelec's 1998 rate restructuring plan orders.~~default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The ~~PPUC required~~agreement allows Met-Ed and Penelec to ~~seek an IRS ruling regarding~~sell the ~~return~~output of certain unamortized investment tax credits and excess deferred income tax benefits to customers. Should the IRS ruling ultimately support returning these tax benefits to customers, there would be no effect to FirstEnergy's, Met-Ed's or Penelec's net income since the contingency existed priorNUG energy to the ~~merger. As a result of their generating asset divestitures, Met-Ed~~market and ~~Penelec obtain their supply of electricity~~requires FES to ~~meet their PLR obligations almost entirely from contracted and open market purchases. In 2000, Met-Ed and Penelec filed a petition with~~provide energy at fixed prices to replace any NUG energy sold to the ~~PPUC seeking permission to defer,~~extent needed for future recovery, energy costs in excess of amounts reflected in their capped generation rates; the PPUC subsequently consolidated this petition in January 2001 with the FirstEnergy/GPU merger proceeding. In June 2001, the PPUC entered orders approving the Settlement Stipulation with all of the major parties in the combined merger and rate relief proceedings which approved the merger and provided Met-Ed and Penelec PLR rate relief. The PPUC permitted Met-Ed and Penelec to ~~defer for future recovery~~satisfy their PLR and default service obligations. The fixed price under the ~~difference between their actual energy costs and those reflected in their capped generation rates, retroactive~~agreement is expected to ~~January 1, 2001. Correspondingly, in~~remain below wholesale market prices during the ~~event that energy costs incurred by~~term of the agreement. If Met-Ed and Penelec ~~are~~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, ~~their respective capped~~if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation ~~rates, that difference will reduce costs that had been deferred for recovery~~rate caps in ~~future periods. This deferral accounting procedure will cease on December 31, 2005. Thereafter, costs which had been deferred through that date would~~2010, timely regulatory relief is not likely to be ~~recoverable through application of competitive transition charge (CTC) revenues received~~granted by the PPUC.

Met-Ed and Penelec ~~through December 31, 2010.~~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 ~~PLR obligations extend~~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 ~~December 31, 2010; during that period CTC revenues will~~a CBP as the amount of supply provided under the then existing FES agreement was to be ~~applied first to PLR costs, then to non-nonutility generation (NUG) stranded costs and finally to NUG stranded costs.~~phased out. Met-Ed and Penelec ~~would be permitted to recover any remaining~~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 ~~through a continuation~~were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the ~~CTC after 4~~ ~~December 31, 2010~~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 ~~later than December 31, 2015. Any amounts not expected~~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 ~~be recovered~~NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by ~~December 31, 2015 would be written off at~~$80 million and $19 million, respectively. These decreases were offset by the ~~time such nonrecovery becomes probable. Several parties had~~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 ~~Petitions~~a Petition for Review ~~in June and July 2001~~ with the Commonwealth Court of Pennsylvania ~~regarding~~asking the ~~June 2001 PPUC orders. On February 21, 2002,~~court to review the ~~Court affirmed~~PPUC’s determination on transmission (including congestion) and the PPUC decision regarding the FirstEnergy/GPU merger, remanding the decision to the PPUC only with respect to the issue of merger savings. The Court reversed the PPUC's decision regarding the PLR obligations oftransmission deferral. Met-Ed and Penelec and rejected those parts of the settlement that permitted the companies to defer for accounting purposes the difference between their non-NUG wholesale power costs and the amount that they collect from retail customers. FirstEnergy and the PPUC each filed a Petition for ~~Allowance~~Review on April 13, 2007 on the issues of ~~Appeal with~~consolidated tax savings and the ~~Pennsylvania Supreme Court~~requested generation rate increase. The OCA filed its Petition for Review on ~~March 25, 2002, asking it~~April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to review the Commonwealth Court decision. Also on March 25, 2002, one intervenor filed a motion seeking an appeal of the Commonwealth Court's decision to affirm the FirstEnergy and GPU merger with the Supreme Court of Pennsylvania. Intake place in September ~~2002,~~2008. If Met-Ed and Penelec ~~established reserves for their PLR deferred energy costs. The reserves reflect~~do not prevail on the ~~potential~~issue of congestion, it could have a material adverse ~~impact~~effect on the results of a pending Pennsylvania Supreme Court decision as to whether or not it will review the Commonwealth Court ruling. In the original interim financial statements for the quarter ended March 31, 2002, FirstEnergy,operations of Met-Ed, Penelec and FirstEnergy.

On April 14, 2008, Met-Ed and Penelec filed annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The proposed TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed has proposed a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.

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

On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy. The final form of this pending legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its ~~independent accountants,~~operations.

(D) NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31, 2008, the accumulated deferred cost balance totaled approximately $264 million.

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

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 with comments from interested parties due on May 16, 2008.

New Jersey statutes require that the ~~finalization~~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 ~~that potential pre-acquisition contingency~~the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in the fall of 2006 and in early 2007.

On April 17, 2008, a draft EMP was released for public comment. The draft EMP establishes four major goals:

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

·	reduce peak demand for electricity by 5,700 MW by 2020 (amounting to about a 22% reduction in projected demand);

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

·	develop low carbon emitting, efficient power plants and close the gap between the supply and demand for electricity.

Following the public comment period which is expected to extend into July 2008, a final EMP will be issued to be followed by appropriate legislation and regulation as necessary. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations or those of JCP&L.

On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the ~~FirstEnergy/GPU merger~~regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments that were submitted in September and October 2007. Final regulations (effective upon publication) were published in the New Jersey Register March 17, 2008. Upon preliminary review of the new regulations, FirstEnergy does not expect a material impact on its operations or those of JCP&L.

(E) FERC MATTERS

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate so-called “pancaking” of transmission charges between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the second quarter of 2008.

PJM Transmission Rate Design

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

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. The FERC’s orders on PJM rate design will prevent the allocation of ~~the purchase price prior to the end~~a portion of the ~~third quarter~~revenue requirement of ~~2002. During~~existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the ~~third quarter~~FERC’s decision to allocate the cost of ~~2002~~new 500 kV and ~~in connection with FirstEnergy finalizing~~above transmission facilities on a PJM-wide basis will reduce future transmission revenue recovery from the ~~purchase accounting relating to the FirstEnergy/GPU merger,~~JCP&L, Met-Ed and Penelec ~~revised~~zones. A partial settlement agreement addressing the ~~previously disclosed accounting~~“beneficiary pays” methodology for ~~this potential pre-acquisition contingency after further consultation with its independent accountants. Accordingly, Met-Ed~~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 ~~Penelec amended their interim financial statements~~was certified by the Presiding Judge. The FERC’s action on the settlement agreement is pending. The remaining merchant transmission cost allocation issues will proceed to hearing in May 2008. On February 13, 2008, AEP appealed the FERC’s orders to the federal Court of Appeals for the ~~quarter ended March~~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, ~~2002 to reflect establishment~~2008. As a result of the ~~reserves~~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 ~~first quarter~~local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. A rehearing request by AEP is pending before the FERC.

Distribution of 2002 totaling $103.0 million at Met-Ed and $111.1 million at Penelec, with a corresponding increase in goodwill, net of tax ($60.3 million at Met-Ed and $65.0 million at Penelec). In addition, net incomeMISO Network Service Revenues

Effective February 1, 2008, the MISO Transmission Owners Agreement provides for the quarter ended March 31, 2002 increased $7.5 million for Met-Ed and $4.7 million for Penelec from the amounts previously reported. The increase in net income reflects the difference between the non-NUG cost of power and the amounts that Met-Ed and Penelec collected from their customers for the quarter ended March 31, 2002. That difference had been previously reflected as a change in the method of distributing transmission revenues among the transmission owners. MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation. This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.

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

On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. This matter is currently pending before the FERC.

MISO Ancillary Services Market and Balancing Area Consolidation

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

Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join the MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.

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

On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators can contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfies the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. FirstEnergy is participating in the May 2008 RPM auction for the 2011-2012 RPM delivery year.

MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory ~~assets based~~agency establishes a different planning reserve for load serving entities in its state. FirstEnergy generally supports the proposal as it promotes a mechanism that will result in long-term commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the ~~PPUC decision. Since these revisions~~filing were filed on January 28, 2008. The FERC approved MISO’s Resource Adequacy proposal on March 26, 2008. Rehearing requests are pending on the FERC’s March 26 Order. A compliance filing establishing the enforcement mechanism for the reserve margin requirement is due on or before June 25, 2008.

Organized Wholesale Power Markets

On February 21, 2008, the FERC issued a NOPR through which it proposes to adopt new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FirstEnergy does not ~~significant to FirstEnergy's consolidated financial statements for this period, there~~believe that the proposed rule will ~~be no restatement of FirstEnergy's consolidated financial statements. The following tables summarize the~~have a significant impact on ~~net income for Met-Ed and Penelec for~~its operations. Comments on the first quarter of 2002. Met-Ed 3 Months Ended, ------ --------------- March 31, 2002 -------------- Net income as previously reported.... $19,118 Effect of revision................... 7,494 ------- Net income as revised................ $26,612 ======= Penelec 3 Months Ended, ------- --------------- March 31, 2002 -------------- Net income as previously reported.... $14,147 Effect of revision................... 4,692 ------- Net income as revised................ $18,839 ======= 5 - NEW ACCOUNTING STANDARDS: The Financial Accounting Standards Board (FASB) approved NOPR were filed on April 18, 2008.

12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," on June 29, 2001. SFAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for using purchase accounting. The provisions of the new standard relating to the determination of goodwill and other intangible assets have been applied to the GPU merger, which was accounted for as a purchase transaction, and have not materially affected the accounting for this transaction. Under SFAS 142, amortization of existing goodwill ceased January 1, 2002. Instead, goodwill will be tested for impairment at least on an annual basis -- no impairment of goodwill is anticipated as a result of a preliminary analysis. Prior to the adoption of SFAS 142, FirstEnergy amortized about $57 million ($.25 per share of common stock) of goodwill annually. There was no goodwill amortization in 2001 associated with the GPU merger under the provisions of the new standard. FirstEnergy's net income in the first quarter of 2001 and the year 2001 of $98 million and $646 million, respectively, would have been $111 million and $701 million, respectively, excluding goodwill amortization. 5 141(R) – “Business Combinations”

In ~~June 2001,~~December 2007, the FASB issued SFAS ~~143, "Accounting~~141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for ~~Asset Retirement Obligations."~~all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. The ~~new statement provides accounting standards~~Standard includes both core principles and pertinent application guidance, eliminating the need for ~~retirement obligations associated with tangible long-lived assets, with adoption required~~numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, ~~2003. SFAS 143 requires~~2009. In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that ~~the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized~~were established as part of a business combination prior to the ~~carrying amount~~implementation of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. Upon retirement, a gain or loss will be recorded if the cost to settle the retirement obligation differs from the carrying amount.this Standard. FirstEnergy is currently ~~assessing~~evaluating the ~~new standard and has not yet determined the~~ impact of adopting this Standard on its financial statements.

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

In ~~September 2001,~~December 2007, the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS 144 supersedes SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." The Statement also supersedes the160 that establishes accounting and reporting ~~provisions~~standards for the noncontrolling interest in a subsidiary and for the deconsolidation of ~~APB 30. FirstEnergy's~~a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption ~~of this~~is prohibited. The Statement effective January 1, 2002, will result in its accounting for any future impairments or disposals of long-lived assets under the provisions of SFAS 144, but will not change the accounting principles used in previous asset impairments or disposals. Application of SFAS 144 is not ~~anticipated~~expected to have a ~~major~~material impact on FirstEnergy’s financial statements.

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

In March 2008, the FASB issued SFAS 161, which requires enhancements to the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting ~~for impairments or disposal transactions compared~~designation. This disclosure is intended to better convey the ~~prior application~~purpose of ~~SFAS 121 or APB 30. 6 -~~derivatives use in terms of the risks that the entity is intending to manage. The FASB believes disclosing the fair values of derivative instruments and their gains and losses in a tabular format is designed to provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide financial statement users information on the potential effect on an entity’s liquidity from using derivatives. Finally, this Statement requires cross-referencing within the footnotes, which is intended to help users of financial statements locate important information about derivative instruments. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

13. SEGMENT ~~INFORMATION:~~ INFORMATION

FirstEnergy ~~operates under the following~~has three reportable operating segments: ~~regulated~~energy delivery services, competitive energy services and ~~other (primarily corporate support services and international operations). FirstEnergy's primary~~Ohio transitional generation services. The “Other” segment is regulated services, which include eight electric utility operating companies in Ohio, Pennsylvania and New Jersey that provide electric transmission and distribution services. Its other material business segmentprimarily consists of telecommunications services. The assets and revenues for the ~~subsidiaries that operate unregulated~~other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”

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

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

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 ~~regulated franchise~~non-shopping customers ~~who have not chosen an alternative,~~under the PLR obligations of the Ohio Companies. Its results reflect the purchase of electricity from the competitive ~~generation supplier. The regulated~~energy services segment ~~obtains a portion~~through full-requirements PSA arrangements, the deferral and amortization of ~~its required~~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 through power supply agreements with the competitive services segment. Segment Financial Information ----------------------------- Regulated Competitive Reconciling Services Services Other Adjustments Consolidated -------- -------- ----- ----------- ------------ (In millions) Three Months Ended: - ------------------- March 31, 2002 -------------- External revenues............. $ 1,995 $ 678 $123 $ 6 (a) $ 2,802 Internal revenues............. 355 410 117 (882)(b) -- Total revenues.............. 2,350 1,088 240 (876) 2,802 Depreciation and amortization. 244 7 12 -- 263 Net interest charges.......... 161 10 103 (14)(b) 260 Income taxes.................. 162 (41) (40) -- 81 Income before cumulative effectload. This segment’s total assets consist of a change in accounting.................. 198 (60) (53) -- 85 Net income (loss)............. 198 (60) (22) -- 116 Total assets.................. 29,147 2,706 6,288 (836)(b) 37,305 Property additions............ 144 37 14 -- 195 March 31, 2001 -------------- External revenues............. $ 1,309 $ 633 $ 1 $ 43 (a) $ 1,986 Internal revenues............. 334 500 65 (899)(b) -- Total revenues.............. 1,643 1,133 66 (856) 1,986 Depreciation and amortization. 215 4 8 -- 227 Net interest charges.......... 145 (4) 8 (23)(b) 126 Income taxes.................. 67 13 4 -- 84 Income before cumulative effect of a change in accounting.................. 123 (24) 7 -- 106 Net income (loss)............. 123 (32) 7 -- 98 Total assets.................. 15,624 1,896 481 -- 18,001 Property additions............ 53 94 4 -- 151 accounts receivable for generation revenues from retail customers.

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

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

Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial ~~reporting: (a) Principally fuel marketing~~reporting primarily consist of interest expense related to holding company debt, corporate support services revenues ~~which are reflected as reductions to~~and expenses ~~for internal management reporting purposes. (b) Elimination~~and elimination of intersegment transactions. 6

PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended March 31, ------------------------- 2002 2001 -------- -------- (Restated) (In thousands) OPERATING REVENUES.............................................................. $242,820 | $243,827 -------- | -------- | OPERATING EXPENSES AND TAXES: | Purchased power.............................................................. 138,129 | 169,064 Other operating costs........................................................ 33,800 | 43,083 -------- | -------- Total operation and maintenance expenses................................. 171,929 | 212,147 Provision for depreciation and amortization.................................. 14,831 | 14,529 General taxes................................................................ 15,030 | 11,690 Income taxes (benefit)....................................................... 12,499 | (3,336) -------- | -------- Total operating expenses and taxes....................................... 214,289 | 235,030 -------- | -------- | OPERATING INCOME................................................................ 28,531 | 8,797 | OTHER INCOME.................................................................... 298 | 605 -------- | -------- | INCOME BEFORE NET INTEREST CHARGES.............................................. 28,829 | 9,402 -------- | -------- | | NET INTEREST CHARGES: | Interest on long-term debt................................................... 8,421 | 8,241 Allowance for borrowed funds used during construction........................ (120) | (144) Deferred interest............................................................ (751) | -- Other interest expense ...................................................... 605 | 1,575 Subsidiaries' preferred stock dividend requirements.......................... 1,835 | 1,835 -------- | -------- Net interest charges..................................................... 9,990 | 11,507 -------- | -------- | NET INCOME (LOSS)............................................................... $ 18,839 | $ (2,105) ======== | ======== ~~The preceding Notes to Financial Statements as they relate to the Pennsylvania Electric Company are an integral part~~
14. SUPPLEMENTAL GUARANTOR INFORMATION

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of ~~these statements.~~ 73

76 ~~REPORT OF INDEPENDENT ACCOUNTANTS To~~ the ~~Board~~leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.

The consolidating statements of ~~Directors~~income for the three months ended March 31, 2008 and ~~Shareholders of Pennsylvania Electric Company: We have reviewed the accompanying consolidated~~2007, consolidating balance ~~sheet of Pennsylvania Electric Company and its subsidiaries~~sheets as of March 31, ~~2002,~~2008 and ~~the related consolidated~~December 31, 2007 and condensed consolidating statements of ~~income and~~ cash flows for the ~~three-month period~~three months ended March 31, ~~2002. These~~2008 and 2007 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

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

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

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

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

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

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

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

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

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

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

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

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

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

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

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

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

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

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

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

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

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

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

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

LIABILITIES AND CAPITALIZATION

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

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

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

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATING BALANCE SHEETS
(Unaudited)

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

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

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

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

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

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

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

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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

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

NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES	$	273,827		$	(122,171	)	$	8,108		$	188		$	159,952

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		400,000			646,975			234,921			-			1,281,896
Redemptions and Repayments-
Long-term debt		-			(135,063	)		(153,540	)		-			(288,603	)
Common stock dividend payments		(10,000	)		-			-			-			(10,000	)
Net cash provided from financing activities		390,000			511,912			81,381			-			983,293

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(19,406	)		(375,391	)		(81,545	)		(187	)		(476,529	)
Proceeds from asset sales		-			5,088			-			-			5,088
Sales of investment securities held in trusts		-			-			173,123			-			173,123
Purchases of investment securities held in trusts		-			-			(181,079	)		-			(181,079	)
Loans to associated companies, net		(644,604	)		-			-			-			(644,604	)
Other		183			(19,438	)		12			(1	)		(19,244	)
Net cash used for investing activities		(663,827	)		(389,741	)		(89,489	)		(188	)		(1,143,245	)

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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

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

NET CASH PROVIDED FROM
OPERATING ACTIVITIES	$	65,870		$	55,003		$	177,456		$	-		$	298,329

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Equity contribution from parent		700,000			700,000			-			(700,000	)		700,000
Short-term borrowings, net		250,000			-			-			(52,269	)		197,731
Redemptions and Repayments-
Long-term debt		-			(616,728	)		(128,716	)		-			(745,444	)
Short-term borrowings, net		-			(52,269	)		-			52,269			-
Net cash provided from (used for) financing activities		950,000			31,003			(128,716	)		(700,000	)		152,287

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(214	)		(81,400	)		(35,892	)		-			(117,506	)
Sales of investment securities held in trusts		-			-			178,632			-			178,632
Purchases of investment securities held in trusts		-			-			(188,076	)		-			(188,076	)
Loans to associated companies, net		(316,003	)		-			(3,895	)		-			(319,898	)
Investment in subsidiary		(700,000	)		-			-			700,000			-
Other		347			(4,606	)		491			-			(3,768	)
Net cash used for investing activities		(1,015,870	)		(86,006	)		(48,740	)		700,000			(450,616	)

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

ITEM 4T. CONTROLS AND PROCEDURES – OE, CEI, TE AND PENELEC (Restated)

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

In the original Form 10-Q for the first quarter of 2008, each registrant’s chief executive officer and chief financial ~~statements are the responsibility~~officer concluded that, as of the ~~Company's management. We conducted our~~end of the period covered by that report, the applicable registrant's disclosure controls and procedures were effective as of March 31, 2008. Subsequent to the restatement of the respective registrants’ Consolidated Statements of Cash Flows discussed in the revised Note 1 to the Combined Notes to Consolidated Financial Statements included in the Form 10-Q/A, each registrant's chief executive officer and chief financial officer performed an updated review and evaluated such registrant's disclosure controls and procedures. Based upon that updated evaluation and as a result of the material weakness in ~~accordance with standards established~~the internal controls over the preparation and review of the Consolidated Statement of Cash Flows discussed below, those officers concluded that, as of the end of the period covered by this report, the applicable registrant's disclosure controls and procedures were ineffective as of March 31, 2008.

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 ~~American Institute~~registrant in the reports that it files or submits under the Securities Exchange Act of ~~Certified Public Accountants. A review of interim financial~~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 ~~consists principally of applying analytical procedures~~required to ~~financial data~~be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, 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 madecommunicated to the ~~accompanying consolidated interim~~registrant's management, including its principal executive and principal financial ~~statements, after~~officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As reported in this Form 10-Q/A, each registrant has amended its original Form 10-Q for the ~~restatement described~~first quarter of 2008 to restate its Consolidated Statements of Cash Flows for the three months ended March 31, 2008, to correct common stock dividend payments reported in ~~Note 4,~~cash flows from financing activities. The Consolidated Statements of Cash Flows for ~~them to be in conformity with accounting principles generally accepted in~~each registrant, as originally filed, erroneously did not reflect the ~~United States~~payment of ~~America. PricewaterhouseCoopers LLP Cleveland, Ohio May 15, 2002, except as to Note 4, which is as of November 26, 2002 77~~ PENNSYLVANIA ELECTRIC COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern, western, and south central parts of Pennsylvania, offering regulated electric distribution services. Penelec also provides power to those customers electing to retain them as their power supplier. Penelec's regulatory plan requires it to itemize, or unbundle, the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Penelec was formerly a wholly owned subsidiary of GPU, Inc., which merged with FirstEnergy on November 7, 2001. Results of Operations - --------------------- Operating revenues decreased by $1.0 million or 0.4%common stock dividends in the first quarter of ~~2002 compared to the first quarter of 2001. The sources of the changes~~2008, which were declared in operating revenues, as compared to the same period in 2001, are summarized in the following table. Sources of Operating Revenue Changes --------------------------------------------------------------------- Increase (Decrease) (In millions) Change in kilowatt-hour sales due to level of retail customers shopping for generation service ............. $ 35.4 Change in other retail kilowatt-hour sales................ (5.5) Decrease in wholesale sales............................... (27.9) Provision for rate refunds................................ (0.8) All other changes......................................... (2.2) --------------------------------------------------------------------- Net Decrease in Operating Revenues........................ $ (1.0) ===================================================================== Electric Sales In the first quarter of 2002, a significant reduction in the number of customers who received their power from alternate suppliers continued to have an effect on operating revenues. During the first quarter of 2001, 25.9% of kilowatt-hour deliveries were from shopping customers, whereas only 4.4% of kilowatt-hour deliveries during the first quarter of 2002 were from shopping customers. More than offsetting this increase in revenues from returning shopping customers was lower kilowatt-hour deliveries to residential customers, primarily due to milder weather during the first quarter of 2002 compared to the first quarter of 2001. Sales to industrial customers also decreased due to a decline in economic conditions; lower sales to wholesale customers in the first quarter of 2002 also reduced operating revenues. Changes in kilowatt-hour deliveries by customer class during the first quarter of 2002, as compared to the same period of 2001, are summarized in the following table: Changes in Kilowatt-hour Deliveries ------------------------------------------------ Increase (Decrease) Residential.................. (3.8)% Commercial................... (0.1)% Industrial................... (16.5)% ------------------------------------------------ Total Retail................. (10.8)% Wholesale.................... (81.4)% ------------------------------------------------ Total Deliveries............. (20.4)% ------------------------------------------------ Operating Expenses and Taxes Total operating expenses and taxes decreased $20.7 million in the first quarter of 2002 compared to the same period of 2001. Purchased power costs decreased $30.9 million in the first quarter of 2002 compared to the first quarter of 2001 primarily due to the absence in 2002 of a $16.0 million charge related to the termination of a wholesale energy contract in 2001. A $9.3 million decrease in other operating costs in the first quarter of 2002 compared to the same period of 2001 was primarily attributable to the absence of costs related to early retirement programs offered to certain bargaining unit employees in 2001. 78 Net Interest Charges Net interest charges decreased by $1.5 million in the first three months of 2002, compared to the same period in 2001. The decrease was attributed to higher deferred interest related to Penelec's deferred energy costs and lower short-term borrowing levels. Financial Statements Revision During the third quarter of ~~2002, Penelec established~~2007. The corrections resulted in a ~~reserve and recorded~~corresponding change in operating liabilities - accounts payable, included in cash flows from operating activities.

A material weakness is a ~~non-cash charge for deferred energy costs incurred subsequent to~~deficiency, or a combination of deficiencies in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the merger (see Pennsylvania Regulatory Matters). The reserve reflects the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. In the originally filedcompany's annual or interim financial statements will not be prevented or detected on a timely basis.

The restatement described above resulted from a material weakness in the internal controls over one aspect of the preparation and review of the Consolidated Statements of Cash Flows. Specifically, the registrants did not have a control that was designed to ensure that declared but unpaid dividends to the registrants’ parent were not reported as cash used for financing activities. This control deficiency resulted in a material misstatement of the registrants’ interim and annual consolidated financial statements. Accordingly, management determined that this control deficiency constitutes a material weakness. The registrants modified their internal controls over the preparation and review of their Consolidated Statements of Cash Flows during the fourth quarter of 2008. Management has implemented a process to segregate dividend declarations with payments applicable to future reporting periods in a unique general ledger account in order to distinguish associated company dividends payable from other associated company accounts payable. Management believes that this process enhances the existing internal controls over financial reporting and remediated the material weakness discussed above for each of the registrants.

(b) CHANGES IN INTERNAL CONTROLS

During the quarter ended March 31, ~~2002,~~2008, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.

Exhibit Number


OE
	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
	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
	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
	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

Pursuant to reporting requirements of respective financings, OE and Penelec ~~had previously disclosed, in consultation with its independent accountants, that the finalization of that potential pre-acquisition contingency relating~~are required to ~~the FirstEnergy/GPU merger would be reflected~~file fixed charge ratios as an ~~adjustment~~exhibit to ~~the allocation~~this Form 10-Q. Pursuant to paragraph (b)(4)(iii)(A) of ~~the purchase price prior~~Item 601 of Regulation S-K, neither OE, CEI, TE nor Penelec have filed as an exhibit to the end of the third quarter of 2002. During the third quarter of 2002 and in connection with FirstEnergy finalizing the purchase accounting relating to the FirstEnergy/GPU merger, Penelec revised the previously disclosed accounting for this potential pre-acquisition contingency after further consultation with its independent accountants. This resulted in the recognition of a reserve related to deferred energy costs. Accordingly, Penelec amended its interim consolidated financial statements for the quarter ended March 31, 2002 to reflect an increase of net income by approximately $4.7 million related to changes in PLR related energy costs incurred that had been previously reflected as changes to its regulatory assets (see Note 4). Should the Pennsylvania Supreme Court ultimately uphold FirstEnergy's appeal, the charge relating to 2002 would be reversed into earnings. Capital Resources and Liquidity - ------------------------------- Penelec has continuing cash requirements for planned capital expenditures and maturing debt. During the remaining three quarters of 2002, capital requirements for property additions and capital leases are expected to be about $75 million. Penelec also has sinking fund requirements for maturing long-term debt of $50.2 million during the remainder of 2002. These requirements are expected to be satisfied from internal cash and/or short-term credit arrangements. As of March 31, 2002, Penelec had about $18.5 million of cash and temporary investments and $38.1 million of short-term indebtedness. Penelec may borrow from its affiliates on a short-term basis. Penelec will not issue first mortgage bonds (FMBs) other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) it from issuingForm 10-Q any debt which is senior to the senior notes. As of March 31, 2002, Penelec had the capability to issue $450 million of additional senior notes based upon FMB collateral. Penelec has no restrictions on the issuance of preferred stock. Market Risk Information - ----------------------- Penelec uses various market sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. Penelec's Risk Policy Committee, comprised of FirstEnergy executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk Penelec is exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, Penelec uses a variety of derivative instruments, including options and futures contracts. The derivatives are used principally for hedging purposes. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 2002 is summarized in the following table: Change in the Fair Value of Commodity Derivative Contracts ---------------------------------------------------------- (In millions) Outstanding as of December 31, 2001. ...... $1.3 Contract value when entered................ 0.2 Increase in value of existing contracts.... 9.0 ---------------------------------------------------------- Outstanding as of March 31, 2002........... $10.5 ========================================================== 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, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec utilizes these results in developing estimates of fair value for the later years of applicable electricity contracts for both financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: 79 Source of Information - Fair Value by Contract Year --------------------------------------------------- 2002* 2003 2004 Thereafter Total --------------------------------------------------------------------------- (In millions) Prices actively quoted.... $ -- $0.9 $0.9 $ -- $1.8 Prices based on models**.. -- -- -- 8.7 8.7 --------------------------------------------------------------------------- Total........... ....... $ -- $0.9 $0.9 $8.7 $10.5 =========================================================================== * For the remaining quarters of 2002. ** Relates to an embedded option that is offset by a regulatory liability and does not affect earnings. Penelec performs sensitivity analyses to estimate its exposure to the market risk of its commodity position. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on Penelec's consolidated financial position or cash flows as of March 31, 2002. Pennsylvania Regulatory Matters - ------------------------------- In June and July 2001, several parties had filed Petitions for Review with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders which approved the FirstEnergy/GPU merger and provided rate relief for Penelec. On February 21, 2002, the Court affirmed the PPUC decision regarding the FirstEnergy/GPU merger, remanding the decision to the PPUC onlyinstrument with respect to long-term debt if the ~~issue~~respective total amount of ~~merger savings. The Court reversed the PPUC's decision regarding Penelec's PLR obligation, and rejected those parts~~securities authorized thereunder does not exceed 10% of ~~the settlement that permitted the Company~~its respective total assets, but each hereby agrees to defer for accounting purposes the difference between its wholesale power costs and the amount collected from retail customers. Penelec and PPUC each filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court on March 25, 2002, asking it to review the Commonwealth Court's decision. Also on March 25, 2002, Citizens Power filed a motion seeking an appeal of the Commonwealth Court's decision to affirm the FirstEnergy/GPU merger with the Supreme Court of Pennsylvania (see Financial Statements Revision and Note 4). Significant Accounting Policies - ------------------------------- Penelec prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect its financial results. All of Penelec's assets are subject to their own specific risks and uncertainties and are periodically reviewed for impairment. Assets relatedfurnish to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Penelec's more significant accounting policies are described below. Purchase Accounting - Acquisition of GPU On November 7, 2001, the merger between FirstEnergy and GPU became effective, and Penelec became a wholly owned subsidiary of FirstEnergy. The merger was accounted for by the purchase method of accounting, which requires judgment regarding the allocation of the purchase price basedSEC on the fair values of the assets acquired (including intangible assets) and the liabilities assumed. The fair values of the acquired assets and assumed liabilities were based primarily on estimates. The adjustments reflected in Penelec's records, which are subject to adjustment in 2002 when finalized, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill, which will be reviewed for impairment at least annually. As of March 31, 2002, Penelec had recorded goodwill of approximately $862.3 million related to the merger. Regulatory Accounting Penelec is subject to regulation that sets the prices (rates) it is permitted to charge customers based on costs that regulatory agencies determine Penelec is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Pennsylvania, a significant amount of regulatory assets have been recorded - $649.8 million as of March 31, 2002. Penelec regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. 80 Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result,request any such expectations and intentions must be documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. Penelec continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, Penelec enters into commodities contracts, which increase the impact of derivative accounting judgments. Revenue Recognition Penelec follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but have not been billed through March 31, 2002. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Recently Issued Accounting Standards Not Yet Implemented - -------------------------------------------------------- In June 2001, the Financial Accounting Standards Board issued SFAS 143, "Accounting for Asset Retirement Obligations." The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets with adoption required as of January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases resulting in a period expense. Upon retirement, a gain or loss will be recorded if the cost to settle the retirement obligation differs from the carrying amount. Penelec is currently assessing its asset retirement obligations under the new standard and has not yet determined the impact on its financial statements. 81 ~~SIGNATURE~~ documents.

	OHIO EDISON COMPANY
	Registrant

	THE CLEVELAND ELECTRIC
	ILLUMINATING COMPANY
	Registrant

	THE TOLEDO EDISON COMPANY
	Registrant

	PENNSYLVANIA ELECTRIC COMPANY
	Registrant

	/s/ Harvey L. Wagner
	Harvey L. Wagner
	Vice President and Controller