UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C.  20549

FORM 10-Q

(Mark One)

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2010

OR

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.
333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
000-53742	FIRSTENERGY SOLUTIONS CORP.	31-1560186
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402
1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-3583	THE TOLEDO EDISON COMPANY	34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-3141	JERSEY CENTRAL POWER & LIGHT COMPANY	21-0485010
	(A New Jersey Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-3522	PENNSYLVANIA ELECTRIC COMPANY	25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes (X)  No (  ) FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company  

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes (X) No (  ) FirstEnergy Corp.

Yes (  ) No (  ) FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

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

Smaller Reporting Company (  ) N/A

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes (  ) No (X) FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

	OUTSTANDING
CLASS	AS OF APRIL 30, 2010
FirstEnergy Corp., $.10 par value	304,835,407
FirstEnergy Solutions Corp., no par value	7
Ohio Edison Company, no par value	60
The Cleveland Electric Illuminating Company, no par value	67,930,743
The Toledo Edison Company, $5 par value	29,402,054
Jersey Central Power & Light Company, $10 par value	13,628,447
Metropolitan Edison Company, no par value	859,500
Pennsylvania Electric Company, $20 par value	4,427,577

FirstEnergy Corp. is the sole holder of FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company common stock.

This combined Form 10-Q is separately filed by FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to any of the FirstEnergy subsidiary registrants is also attributed to FirstEnergy Corp.

FirstEnergy Web Site

Each of the registrants’ Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy's internet Web site at www.firstenergycorp.com.

These reports are posted on the Web site as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, the registrants routinely post important information on the Web site and recognize the Web site is a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under SEC Regulation FD. Information contained on FirstEnergy's Web site shall not be deemed incorporated into, or to be part of, this report.

OMISSION OF CERTAIN INFORMATION

FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

Forward-Looking Statements: This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.

Actual results may differ materially due to:

·   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 Pennsylvania.

·   The impact of the regulatory process on the pending matters in Ohio, Pennsylvania and New Jersey.

·   Business and regulatory impacts from ATSI’s realignment into PJM.

·   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.

·   Operation and maintenance costs being higher than anticipated.

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

·   The potential impacts of the U.S. Court of Appeals’ July 11, 2008 decision requiring revisions to 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 that certain generating units may need to be shut down) or levels of emission reductions related to the Consent Decree resolving the NSR litigation or other potential similar regulatory initiatives or actions.

·   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.

·   Factors that may further delay, or increase the costs associated with (including replacement power costs), the restart of the Davis-Besse Nuclear Power Station from its current refueling outage, including that the modifications to control rod drive mechanism nozzles take longer than expected or are not effective, other conditions requiring remediation are discovered during the extended outage, or the NRC takes adverse action in connection with any of the foregoing.

·   Ultimate resolution of Met-Ed’s and Penelec’s TSC filings with the PPUC.

·   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 and energy efficiency mandates.

·   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 amounts that are 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.

·   Interest rates and any actions taken by credit rating agencies that could negatively affect the registrants’ access to financing or their costs and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.

·   The continuing decline of the national and regional economy and its impact on the registrants’ major industrial and commercial customers.

·   Issues concerning the soundness of financial institutions and counterparties with which the registrants do business.

·   The expected timing and likelihood of completion of the proposed merger with Allegheny Energy, Inc., including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management's time and attention from FirstEnergy’s ongoing business during this time period, the ability to maintain relationships with customers, employees or suppliers as well as the ability to successfully integrate the businesses and realize cost savings and any other synergies and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect.

·   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. A security rating is not a recommendation to buy, sell or hold securities that may be subject to revision or withdrawal at any time by the assigning rating organization. Each 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.

TABLE OF CONTENTS

		Pages
Glossary of Terms		iii-iv
Item 1.    Financial Statements
FirstEnergy Corp.
	Consolidated Statements of Income	1
	Consolidated Statements of Comprehensive Income	2
	Consolidated Balance Sheets	3
	Consolidated Statements of Cash Flows	4
FirstEnergy Solutions Corp.
	Consolidated Statements of Income and Comprehensive Income	5
	Consolidated Balance Sheets	6
	Consolidated Statements of Cash Flows	7
Ohio Edison Company
	Consolidated Statements of Income and Comprehensive Income (Loss)	8
	Consolidated Balance Sheets	9
	Consolidated Statements of Cash Flows	10
The Cleveland Electric Illuminating Company
	Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)	11
	Consolidated Balance Sheets	12
	Consolidated Statements of Cash Flows	13
The Toledo Edison Company
	Consolidated Statements of Income and Comprehensive Income (Loss)	14
	Consolidated Balance Sheets	15
	Consolidated Statements of Cash Flows	16
Jersey Central Power & Light Company
	Consolidated Statements of Income and Comprehensive Income	17
	Consolidated Balance Sheets	18
	Consolidated Statements of Cash Flows	19
Metropolitan Edison Company
	Consolidated Statements of Income and Comprehensive Income (Loss)	20
	Consolidated Balance Sheets	21
	Consolidated Statements of Cash Flows	22
Pennsylvania Electric Company
	Consolidated Statements of Income and Comprehensive Income (Loss)	23
	Consolidated Balance Sheets	24
	Consolidated Statements of Cash Flows	25

i

TABLE OF CONTENTS (Cont'd)

	Pages
Combined Notes To Consolidated Financial Statements	26-62
Item 2.   Management's Discussion and Analysis of Registrant and Subsidiaries	63-95
Management's Narrative Analysis of Results of Operations
FirstEnergy Solutions Corp.	96-98
Ohio Edison Company	99-100
The Cleveland Electric Illuminating Company	101-102
The Toledo Edison Company	103-104
Jersey Central Power & Light Company	105-106
Metropolitan Edison Company	107-108
Pennsylvania Electric Company	109-110
Item 3.    Quantitative and Qualitative Disclosures About Market Risk	111
Item 4.    Controls and Procedures – FirstEnergy	111
Item 4T.  Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec	111
Part II.    Other Information
Item 1.    Legal Proceedings	112
Item 1A. Risk Factors	112
Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds	112
Item 5.    Other Information	112
Item 6.    Exhibits	112-113

ii

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:

ATSI	American Transmission Systems, Incorporated, owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial and other corporate support services
FEV	FirstEnergy Ventures Corp., invests in certain unregulated enterprises and business ventures
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., a public utility holding company
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition    Funding	JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds
JCP&L Transition    Funding II	JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition bonds
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies	Met-Ed, Penelec and Penn
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
Shelf Registrants	FirstEnergy, OE, CEI, TE, JCP&L, Met-Ed and Penelec
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak	A joint venture between FirstEnergy Ventures Corp. and Boich Companies, that owns mining and     coal transportation operations near Roundup, Montana
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
Utilities	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
Waverly	The Waverly Power and Light Company, a wholly owned subsidiary of Penelec
The following abbreviations and acronyms are used to identify frequently used terms in this report:
AEP	American Electric Power Company, Inc.
ALJ	Administrative Law Judge
AMP-Ohio	American Municipal Power-Ohio, Inc.
AOCL	Accumulated Other Comprehensive Loss
AQC	Air Quality Control
ARO	Asset Retirement Obligation
BGS	Basic Generation Service
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAVR	Clean Air Visibility Rule
CBP	Competitive Bid Process
CMEC	Capacity market Evolution Committee
CO2	Carbon dioxide
CTC	Competitive Transition Charge
DOE	United States Department of Energy
DOJ	United States Department of Justice
DCPD	Deferred Compensation Plan for Outside Directors
DPA	Department of the Public Advocate, Division of Rate Counsel (New Jersey)
ECAR	East Central Area Reliability Coordination Agreement
EDCP	Executive Deferred Compensation Plan
EE&C	Energy Efficiency and Conservation
EMP	Energy Master Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
EPRI	Electric Power Research Institute

iii

GLOSSARY OF TERMS, Cont'd.

ESOP	Employee Stock Ownership Plan
ESP	Electric Security Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FMB	First Mortgage Bond
FPA	Federal Power Act
FRR	Fixed Resource Requirement
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
IBEW	International Brotherhood of Electrical Workers
IFRS	International Financial Reporting Standards
IRS	Internal Revenue Service
JCARR	Joint Committee on Agency Review
kV	Kilovolt
KWH	Kilowatt-hours
LED	Light-emitting Diode
LIBOR	London Interbank Offered Rate
LOC	Letter of Credit
LTIP	Long-Term Incentive Plan
MACT	Maximum Achievable Control Technology
MISO	Midwest Independent Transmission System Operator, Inc.
Moody's	Moody's Investors Service, Inc.
MRO	Market Rate Offer
MW	Megawatts
MWH	Megawatt-hours
NAAQS	National Ambient Air Quality Standards
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
NNSR	Non-Attainment New Source Review
NOPEC	Northeast Ohio Public Energy Council
NOV	Notice of Violation
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
OCC	Ohio Consumers’ Counsel
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
OVEC	Ohio Valley Electric Corporation
PCRB	Pollution Control Revenue Bond
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort; an electric utility's obligation to provide generation service to customers     whose alternative supplier fails to deliver service
PPUC	Pennsylvania Public Utility Commission
PSA	Power Supply Agreement
PSD	Prevention of Significant Deterioration
PUCO	Public Utilities Commission of Ohio
QSPE	Qualifying Special-Purpose Entity
RCP	Rate Certainty Plan
RECs	Renewable Energy Credits
RFP	Request for Proposal
RPM	Reliability Pricing Model
RTEP	Regional Transmission Expansion Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
S&P	Standard & Poor's Ratings Service
SB221	Amended Substitute Senate Bill 221
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment

iv

GLOSSARY OF TERMS, Cont'd.

SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
SRECs	Solar Renewable Energy Credits
TBC	Transition Bond Charge
TMI-2	Three Mile Island Unit 2
TSC	Transmission Service Charge
VERO	Voluntary Enhanced Retirement Option
VIE	Variable Interest Entity

v

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In millions, except
	per share amounts)
REVENUES:
Electric utilities	$	2,543		$	3,020
Unregulated businesses		756			314
Total revenues*		3,299			3,334
EXPENSES:
Fuel		334			312
Purchased power		1,238			1,143
Other operating expenses		701			827
Provision for depreciation		193			177
Amortization of regulatory assets		212			411
Deferral of new regulatory assets		-			(93	)
General taxes		205			211
Total expenses		2,883			2,988
OPERATING INCOME		416			346
OTHER INCOME (EXPENSE):
Investment income (loss), net		16			(11	)
Interest expense		(213	)		(194	)
Capitalized interest		41			28
Total other expense		(156	)		(177	)
INCOME  BEFORE INCOME TAXES		260			169
INCOME TAXES		111			54
NET INCOME		149			115
Noncontrolling interest loss		(6	)		(4	)
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$	155		$	119
BASIC EARNINGS PER SHARE OF COMMON STOCK	$	0.51		$	0.39
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		304			304
DILUTED EARNINGS PER SHARE OF COMMON STOCK	$	0.51		$	0.39
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		306			306
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.55		$	0.55
* Includes $109 million of excise tax collections in the three months ended March 31, 2010 and 2009.
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

1

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In millions)
NET INCOME	$	149		$	115
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		13			35
Unrealized gain on derivative hedges		4			15
Change in unrealized gain on available-for-sale securities		6			(5	)
Other comprehensive income		23			45
Income tax expense related to other comprehensive income		7			15
Other comprehensive income, net of tax		16			30
COMPREHENSIVE INCOME		165			145
COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST		(6	)		(4	)
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	$	171		$	149
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

2

FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2010			2009
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	310		$	874
Receivables-
Customers (less accumulated provisions of $36 million and $33 million,
respectively, for uncollectible accounts)		1,255			1,244
Other (less accumulated provisions of $7 million for uncollectible accounts)		140			153
Materials and supplies, at average cost		699			647
Prepaid taxes		236			248
Other		214			154
		2,854			3,320
PROPERTY, PLANT AND EQUIPMENT:
In service		27,980			27,826
Less - Accumulated provision for depreciation		11,554			11,397
		16,426			16,429
Construction work in progress		2,931			2,735
		19,357			19,164
INVESTMENTS:
Nuclear plant decommissioning trusts		1,882			1,859
Investments in lease obligation bonds		495			543
Other		609			621
		2,986			3,023
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,575			5,575
Regulatory assets		2,398			2,356
Power purchase contract asset		148			200
Other		760			666
		8,881			8,797
	$	34,078		$	34,304
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,783		$	1,834
Short-term borrowings		886			1,181
Accounts payable		772			829
Accrued taxes		266			314
Other		1,179			1,130
		4,886			5,288
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 375,000,000 shares-
304,835,407 shares outstanding		31			31
Other paid-in capital		5,432			5,448
Accumulated other comprehensive loss		(1,399	)		(1,415	)
Retained earnings		4,482			4,495
Total common stockholders' equity		8,546			8,559
Noncontrolling interest		(11	)		(2	)
Total equity		8,535			8,557
Long-term debt and other long-term obligations		11,847			11,908
		20,382			20,465
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,602			2,468
Asset retirement obligations		1,449			1,425
Deferred gain on sale and leaseback transaction		984			993
Power purchase contract liability		738			643
Retirement benefits		1,527			1,534
Lease market valuation liability		251			262
Other		1,259			1,226
		8,810			8,551
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
	$	34,078		$	34,304
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these
financial statements.

3

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	149		$	115
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		193			177
Amortization of regulatory assets		212			411
Deferral of new regulatory assets		-			(93	)
Nuclear fuel and lease amortization		41			27
Deferred purchased power and other costs		(77	)		(62	)
Deferred income taxes and investment tax credits, net		59			(28	)
Investment impairment		10			36
Deferred rents and lease market valuation liability		(17	)		(14	)
Stock-based compensation		(15	)		(13	)
Accrued compensation and retirement benefits		(81	)		(66	)
Commodity derivative transactions, net		33			16
Cash collateral paid		(46	)		(15	)
Decrease (increase) in operating assets-
Receivables		2			46
Materials and supplies		(42	)		(7	)
Prepayments and other current assets		33			(71	)
Increase (decrease) in operating liabilities-
Accounts payable		(57	)		(90	)
Accrued taxes		7			(51	)
Accrued interest		66			118
Other		36			26
Net cash provided from operating activities		506			462
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			700
Redemptions and Repayments-
Long-term debt		(109	)		(444	)
Short-term borrowings, net		(295	)		-
Common stock dividend payments		(168	)		(168	)
Other		(22	)		(18	)
Net cash provided from (used for) financing activities		(594	)		70
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(508	)		(654	)
Proceeds from asset sales		114			8
Sales of investment securities held in trusts		733			567
Purchases of investment securities held in trusts		(755	)		(584	)
Customer intangibles		(101	)		-
Cash investments		49			17
Other		(8	)		(32	)
Net cash used for investing activities		(476	)		(678	)
Net change in cash and cash equivalents		(564	)		(146	)
Cash and cash equivalents at beginning of period		874			545
Cash and cash equivalents at end of period	$	310		$	399
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

4

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In thousands)
REVENUES:
Electric sales to affiliates	$	607,302		$	892,690
Electric sales to non-affiliates		668,685			279,746
Other		112,106			53,670
Total revenues		1,388,093			1,226,106
EXPENSES:
Fuel		328,221			306,158
Purchased power from affiliates		60,953			63,207
Purchased power from non-affiliates		450,216			160,342
Other operating expenses		304,510			307,356
Provision for depreciation		62,918			61,373
General taxes		26,746			23,376
Total expenses		1,233,564			921,812
OPERATING INCOME		154,529			304,294
OTHER EXPENSE:
Investment income (loss)		717			(28,874	)
Miscellaneous expense		1,310			2,511
Interest expense to affiliates		(2,305	)		(2,979	)
Interest expense - other		(49,644	)		(22,527	)
Capitalized interest		19,690			10,078
Total other expense		(30,232	)		(41,791	)
INCOME BEFORE INCOME TAXES		124,297			262,503
INCOME TAXES		44,371			91,822
NET INCOME		79,926			170,681
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(9,834	)		2,568
Unrealized gain on derivative hedges		1,274			11,016
Change in unrealized gain on available-for-sale securities		5,028			(1,477	)
Other comprehensive income (loss)		(3,532	)		12,107
Income tax expense (benefit) related to other comprehensive income		(1,340	)		4,709
Other comprehensive income (loss), net of tax		(2,192	)		7,398
TOTAL COMPREHENSIVE INCOME	$	77,734		$	178,079
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

5

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2010			2009
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11		$	12
Receivables-
Customers (less accumulated provisions of $13,641,000 and $12,041,000,
respectively, for uncollectible accounts)		248,994			195,107
Associated companies		360,804			318,561
Other (less accumulated provisions of $6,702,000)		81,659			51,872
Notes receivable from associated companies		483,423			805,103
Materials and supplies, at average cost		558,751			539,541
Prepayments and other		160,668			107,782
		1,894,310			2,017,978
PROPERTY, PLANT AND EQUIPMENT:
In service		10,368,007			10,357,632
Less - Accumulated provision for depreciation		4,617,864			4,531,158
		5,750,143			5,826,474
Construction work in progress		2,597,630			2,423,446
		8,347,773			8,249,920
INVESTMENTS:
Nuclear plant decommissioning trusts		1,091,114			1,088,641
Other		8,525			22,466
		1,099,639			1,111,107
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		66,462			86,626
Goodwill		24,248			24,248
Customer intangibles		114,567			16,566
Property taxes		50,125			50,125
Unamortized sale and leaseback costs		90,803			72,553
Other		109,494			121,665
		455,699			371,783
	$	11,797,421		$	11,750,788
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,601,184		$	1,550,927
Short-term borrowings-
Associated companies		-			9,237
Other		100,000			100,000
Accounts payable-
Associated companies		385,251			466,078
Other		270,457			245,363
Accrued taxes		66,585			83,158
Other		393,512			359,057
		2,816,989			2,813,820
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 750 shares,
7 shares outstanding		1,465,698			1,468,423
Accumulated other comprehensive loss		(105,193	)		(103,001	)
Retained earnings		2,229,075			2,149,149
Total common stockholder's equity		3,589,580			3,514,571
Long-term debt and other long-term obligations		2,660,200			2,711,652
		6,249,780			6,226,223
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		984,440			992,869
Accumulated deferred investment tax credits		57,353			58,396
Asset retirement obligations		936,453			921,448
Retirement benefits		219,174			204,035
Property taxes		50,125			50,125
Lease market valuation liability		250,871			262,200
Other		232,236			221,672
		2,730,652			2,710,745
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	11,797,421		$	11,750,788
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

6

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended
		March 31
		2010			2009
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	79,926		$	170,681
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation			62,918			61,373
Nuclear fuel and lease amortization			42,118			27,169
Deferred rents and lease market valuation liability			(40,869	)		(37,522	)
Deferred income taxes and investment tax credits, net			37,773			24,866
Investment impairment			9,606			33,535
Commodity derivative transactions, net			32,900			15,817
Cash collateral, net			(21,411	)		(5,492	)
Decrease (increase) in operating assets:
Receivables			(158,288	)		80,067
Materials and supplies			(8,700	)		(865	)
Prepayments and other current assets			13,516			(3,456	)
Increase (decrease) in operating liabilities:
Accounts payable			(41,057	)		(61,419	)
Accrued taxes			(16,300	)		39,846
Accrued interest			(14,930	)		10,338
Other			13,902			(7,071	)
Net cash provided from (used for) operating activities			(8,896	)		347,867
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt			-			100,000
Short-term borrowings, net			-			621,294
Redemptions and Repayments-
Long-term debt			(1,278	)		(335,916	)
Short-term borrowings, net			(9,237	)		-
Other			(731	)		-
Net cash provided from (used for) financing activities			(11,246	)		385,378
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(301,603	)		(412,805	)
Proceeds from asset sales			114,272			7,573
Sales of investment securities held in trusts			272,094			351,414
Purchases of investment securities held in trusts			(284,888	)		(356,904	)
Loans from (to) associated companies, net			321,680			(303,963	)
Customer intangibles			(100,615	)		-
Other			(799	)		(18,565	)
Net cash provided from (used for) investing activities			20,141			(733,250	)
Net change in cash and cash equivalents			(1	)		(5	)
Cash and cash equivalents at beginning of period			12			39
Cash and cash equivalents at end of period		$	11		$	34
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

7

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In thousands)
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	479,925		$	720,011
Excise and gross receipts tax collections		28,475			28,980
Total revenues		508,400			748,991
EXPENSES:
Purchased power from affiliates		135,857			332,336
Purchased power from non-affiliates		112,051			137,813
Other operating costs		88,855			157,830
Provision for depreciation		21,880			21,513
Amortization of regulatory assets, net		29,345			20,211
General taxes		47,492			49,120
Total expenses		435,480			718,823
OPERATING INCOME		72,920			30,168
OTHER INCOME (EXPENSE):
Investment income		5,244			9,362
Miscellaneous expense		(292	)		(810	)
Interest expense		(22,310	)		(23,287	)
Capitalized interest		208			220
Total other expense		(17,150	)		(14,515	)
INCOME BEFORE INCOME TAXES		55,770			15,653
INCOME TAXES		19,609			4,005
NET INCOME		36,161			11,648
Noncontrolling interest income		132			146
EARNINGS AVAILABLE TO PARENT	$	36,029		$	11,502
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	36,161		$	11,648
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		4,015			5,738
Change in unrealized gain on available-for-sale securities		291			(2,709	)
Other comprehensive income		4,306			3,029
Income tax expense related to other comprehensive income		693			529
Other comprehensive income, net of tax		3,613			2,500
COMPREHENSIVE INCOME		39,774			14,148
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		132			146
COMPREHENSIVE INCOME AVAILABLE TO PARENT	$	39,642		$	14,002
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

8

OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2010			2009
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	60,680		$	324,175
Receivables-
Customers (less accumulated provisions of $5,417,000 and $5,119,000, respectively,
for uncollectible accounts)		196,226			209,384
Associated companies		49,839			98,874
Other (less accumulated provisions of $1,000 and $18,000, respectively,
for uncollectible accounts)		18,758			14,155
Notes receivable from associated companies		104,183			118,651
Prepayments and other		37,766			15,964
		467,452			781,203
UTILITY PLANT:
In service		3,057,995			3,036,467
Less - Accumulated provision for depreciation		1,177,211			1,165,394
		1,880,784			1,871,073
Construction work in progress		35,331			31,171
		1,916,115			1,902,244
OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds		216,498			216,600
Nuclear plant decommissioning trusts		120,819			120,812
Other		96,669			96,861
		433,986			434,273
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		432,526			465,331
Pension assets		33,128			19,881
Property taxes		67,037			67,037
Unamortized sale and leaseback costs		33,877			35,127
Other		36,454			39,881
		603,022			627,257
	$	3,420,575		$	3,744,977
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,470		$	2,723
Short-term borrowings-
Associated companies		-			92,863
Other		807			807
Accounts payable-
Associated companies		75,374			102,763
Other		32,351			40,423
Accrued taxes		66,100			81,868
Accrued interest		25,523			25,749
Other		109,429			81,424
		311,054			428,620
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 shares outstanding		949,735			1,154,797
Accumulated other comprehensive loss		(159,964	)		(163,577	)
Retained earnings		20,920			29,890
Total common stockholder's equity		810,691			1,021,110
Noncontrolling interest		6,574			6,442
Total equity		817,265			1,027,552
Long-term debt and other long-term obligations		1,160,250			1,160,208
		1,977,515			2,187,760
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		670,758			660,114
Accumulated deferred investment tax credits		11,243			11,406
Asset retirement obligations		87,315			85,926
Retirement benefits		174,404			174,925
Other		188,286			196,226
		1,132,006			1,128,597
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	3,420,575		$	3,744,977
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

9

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	36,161		$	11,648
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		21,880			21,513
Amortization of regulatory assets, net		29,345			20,211
Purchased power cost recovery reconciliation		(5,908	)		2,978
Amortization of lease costs		32,934			32,934
Deferred income taxes and investment tax credits, net		(2,489	)		(7,272	)
Accrued compensation and retirement benefits		(12,160	)		(1,746	)
Accrued regulatory obligations		(623	)		18,350
Electric service prepayment programs		-			(3,944	)
Decrease (increase) in operating assets-
Receivables		65,141			1,435
Prepayments and other current assets		(21,802	)		(9,806	)
Increase (decrease) in operating liabilities-
Accounts payable		(35,461	)		11,880
Accrued taxes		(15,849	)		(26,222	)
Accrued interest		(226	)		(1,956	)
Other		10,270			6,708
Net cash provided from operating activities		101,213			76,711
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		-			79,810
Redemptions and Repayments-
Long-term debt		(1,363	)		(100,393	)
Short-term borrowings, net		(92,863	)
Dividend Payments-
Common stock		(250,000	)		-
Other		(113	)		(69	)
Net cash used for financing activities		(344,339	)		(20,652	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(35,680	)		(37,523	)
Sales of investment securities held in trusts		2,424			9,417
Purchases of investment securities held in trusts		(2,971	)		(10,422	)
Loan repayments from associated companies, net		14,469			146,098
Cash investments		(384	)		(243	)
Other		1,773			1,463
Net cash provided from (used for) investing activities		(20,369	)		108,790
Net change in cash and cash equivalents		(263,495	)		164,849
Cash and cash equivalents at beginning of period		324,175			146,343
Cash and cash equivalents at end of period	$	60,680		$	311,192
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

10

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In thousands)
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	312,497		$	431,405
Excise tax collections		17,573			18,320
Total revenues		330,070			449,725
EXPENSES:
Purchased power from affiliates		94,965			238,872
Purchased power from non-affiliates		51,826			71,746
Other operating costs		31,235			64,830
Provision for depreciation		18,111			18,280
Amortization of regulatory assets		45,139			256,737
Deferral of new regulatory assets		-			(94,816	)
General taxes		38,489			38,141
Total expenses		279,765			593,790
OPERATING INCOME (LOSS)		50,305			(144,065	)
OTHER INCOME (EXPENSE):
Investment income		7,547			8,420
Miscellaneous income		581			1,994
Interest expense		(33,621	)		(33,322	)
Capitalized interest		26			67
Total other expense		(25,467	)		(22,841	)
INCOME (LOSS) BEFORE INCOME TAXES		24,838			(166,906	)
INCOME TAX EXPENSE (BENEFIT)		10,843			(61,506	)
NET INCOME (LOSS)		13,995			(105,400	)
Noncontrolling interest income		419			458
EARNINGS (LOSS) AVAILABLE TO PARENT	$	13,576		$	(105,858	)
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME (LOSS)	$	13,995		$	(105,400	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(22,585	)		3,967
Income tax expense (benefit) related to other comprehensive income		(8,277	)		1,370
Other comprehensive income (loss), net of tax		(14,308	)		2,597
COMPREHENSIVE LOSS		(313	)		(102,803	)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		419			458
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT	$	(732	)	$	(103,261	)
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

11

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,				December 31,
		2010			2009
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	247		$	86,230
Receivables-
Customers (less accumulated provisions of $5,168,000 and
$5,239,000, respectively, for uncollectible accounts)			200,840			209,335
Associated companies			57,338			98,954
Other			5,058			11,661
Notes receivable from associated companies			25,376			26,802
Prepayments and other			18,996			9,973
			307,855			442,955
UTILITY PLANT:
In service			2,326,786			2,310,074
Less - Accumulated provision for depreciation			896,146			888,169
			1,430,640			1,421,905
Construction work in progress			33,139			36,907
			1,463,779			1,458,812
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			340,034			388,641
Other			10,210			10,220
			350,244			398,861
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			1,688,521			1,688,521
Regulatory assets			497,723			545,505
Pension assets (Note 5)			-			13,380
Property taxes			77,319			77,319
Other			12,914			12,777
			2,276,477			2,337,502
		$	4,398,355		$	4,638,130
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	127		$	117
Short-term borrowings-
Associated companies			233,710			339,728
Accounts payable-
Associated companies			55,534			68,634
Other			15,879			17,166
Accrued taxes			74,117			90,511
Accrued interest			39,261			18,466
Other			43,663			45,440
			462,291			580,062
CAPITALIZATION:
Common stockholder's equity
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding			884,781			884,897
Accumulated other comprehensive loss			(152,466	)		(138,158	)
Retained earnings			510,824			597,248
Total common stockholder's equity			1,243,139			1,343,987
Noncontrolling interest			17,651			20,592
Total equity			1,260,790			1,364,579
Long-term debt and other long-term obligations			1,852,463			1,872,750
			3,113,253			3,237,329
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			636,324			644,745
Accumulated deferred investment tax credits			11,626			11,836
Retirement benefits			82,281			69,733
Other			92,580			94,425
			822,811			820,739
COMMITMENTS AND CONTINGENCIES (Note 8)
		$	4,398,355		$	4,638,130
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

12

\

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	13,995		$	(105,400	)
Adjustments to reconcile net income (loss) to net cash from operating activities-
Provision for depreciation		18,111			18,280
Amortization of regulatory assets, net		45,139			256,737
Deferral of new regulatory assets		-			(94,816	)
Deferred income taxes and investment tax credits, net		(13,627	)		(61,525	)
Accrued compensation and retirement benefits		2,282			1,828
Accrued regulatory obligations		(26	)		12,057
Electric service prepayment programs		-			(2,695	)
Decrease (increase) in operating assets-
Receivables		70,633			(44,808	)
Prepayments and other current assets		(9,133	)		785
Increase (decrease) in operating liabilities-
Accounts payable		(14,387	)		18,470
Accrued taxes		(16,616	)		(16,274	)
Accrued interest		20,795			27,614
Other		(2,636	)		346
Net cash provided from operating activities		114,530			10,599
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt		(26	)		(181	)
Short-term borrowings, net		(126,334	)		(4,086	)
Dividend Payments-
Common stock		(100,000	)		(10,000	)
Other		(3,365	)		(2,840	)
Net cash used for financing activities		(229,725	)		(17,107	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(19,735	)		(24,900	)
Loans to associated companies, net		1,426			(3,683	)
Redemptions of lessor notes		48,606			37,068
Other		(1,085	)		(1,970	)
Net cash provided from investing activities		29,212			6,515
Net change in cash and cash equivalents		(85,983	)		7
Cash and cash equivalents at beginning of period		86,230			226
Cash and cash equivalents at end of period	$	247		$	233
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

13

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In thousands)
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	125,431		$	237,085
Excise tax collections		7,041			7,729
Total revenues		132,472			244,814
EXPENSES:
Purchased power from affiliates		47,000			125,324
Purchased power from non-affiliates		26,109			40,537
Other operating costs		25,545			45,004
Provision for depreciation		7,950			7,572
Amortization (deferral) of regulatory assets, net		(8,499	)		9,897
General taxes		13,461			14,250
Total expenses		111,566			242,584
OPERATING INCOME		20,906			2,230
OTHER INCOME (EXPENSE):
Investment income		3,800			5,484
Miscellaneous expense		(1,406	)		(1,340	)
Interest expense		(10,487	)		(5,533	)
Capitalized interest		78			42
Total other expense		(8,015	)		(1,347	)
INCOME BEFORE INCOME TAXES		12,891			883
INCOME TAX EXPENSE (BENEFIT)		5,382			(109	)
NET INCOME		7,509			992
Less:  Noncontrolling interest income		3			2
EARNINGS AVAILABLE TO PARENT	$	7,506		$	990
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	7,509		$	992
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		296			133
Change in unrealized gain on available-for-sale securities		369			(809	)
Other comprehensive income (loss)		665			(676	)
Income tax expense (benefit) related to other comprehensive income		170			(19	)
Other comprehensive income (loss), net of tax		495			(657	)
COMPREHENSIVE INCOME		8,004			335
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		3			2
COMPREHENSIVE INCOME AVAILABLE TO PARENT	$	8,001		$	333
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

14

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,				December 31,
		2010			2009
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	87,296		$	436,712
Receivables-
Customers			218			75
Associated companies			58,811			90,191
Other (less accumulated provisions of $207,000 and $208,000,
respectively, for uncollectible accounts)			19,499			20,180
Notes receivable from associated companies			118,689			85,101
Prepayments and other			11,680			7,111
			296,193			639,370
UTILITY PLANT:
In service			921,768			912,930
Less - Accumulated provision for depreciation			431,737			427,376
			490,031			485,554
Construction work in progress			8,913			9,069
			498,944			494,623
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes (Note 7)			103,848			124,357
Nuclear plant decommissioning trusts			73,583			73,935
Other			1,558			1,580
			178,989			199,872
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			500,576			500,576
Regulatory assets			81,616			69,557
Property taxes			23,658			23,658
Other			67,753			55,622
			673,603			649,413
		$	1,647,729		$	1,983,278
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	222		$	222
Accounts payable-
Associated companies			43,730			78,341
Other			7,509			8,312
Notes payable to associated companies			-			225,975
Accrued taxes			20,827			25,734
Lease market valuation liability			36,900			36,900
Other			64,724			29,273
			173,912			404,757
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			178,089			178,181
Accumulated other comprehensive loss			(49,308	)		(49,803	)
Retained earnings			91,995			214,490
Total common stockholder's equity			367,786			489,878
Noncontrolling interest			2,698			2,696
Total equity			370,484			492,574
Long-term debt and other long-term obligations			600,450			600,443
			970,934			1,093,017
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			105,271			80,508
Accumulated deferred investment tax credits			6,258			6,367
Lease market valuation liability (Note 7)			226,975			236,200
Retirement benefits			67,304			65,988
Asset retirement obligations			32,831			32,290
Other			64,244			64,151
			502,883			485,504
COMMITMENTS AND CONTINGENCIES (Note 8)
		$	1,647,729		$	1,983,278
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

15

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	7,509		$	992
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		7,950			7,572
Amortization (deferral) of regulatory assets, net		(8,499	)		9,897
Purchased power cost recovery reconciliation		41			2,912
Deferred rents and lease market valuation liability		6,141			6,141
Deferred income taxes and investment tax credits, net		11,287			(2,151	)
Accrued compensation and retirement benefits		837			397
Accrued regulatory obligations		(246	)		4,450
Electric service prepayment programs		-			(1,240	)
Decrease (increase) in operating assets-
Receivables		45,376			(8,395	)
Prepayments and other current assets		(4,569	)		492
Increase (decrease) in operating liabilities-
Accounts payable		(35,414	)		9,018
Accrued taxes		(4,933	)		(4,904	)
Accrued interest		10,050			4,613
Other		(4,373	)		1,465
Net cash provided from (used for) operating activities		31,157			31,259
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt		-			(181	)
Short-term borrowings, net		(225,975	)		(3,977	)
Dividend Payments-
Common stock		(130,000	)		(10,000	)
Other		(58	)		(39	)
Net cash provided from (used for) financing activities		(356,033	)		(14,197	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(9,597	)		(12,233	)
Loans to associated companies, net		(33,587	)		(21,528	)
Redemption of lessor notes		20,509			18,358
Sales of investment securities held in trusts		31,067			44,270
Purchases of investment securities held in trusts		(31,705	)		(44,856	)
Other		(1,227	)		(1,072	)
Net cash provided from (used for) investing activities		(24,540	)		(17,061	)
Net change in cash and cash equivalents		(349,416	)		1
Cash and cash equivalents at beginning of period		436,712			14
Cash and cash equivalents at end of period	$	87,296		$	15
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

16

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In thousands)
REVENUES:
Electric sales	$	691,392		$	760,920
Excise tax collections		12,352			12,731
Total revenues		703,744			773,651
EXPENSES:
Purchased power		414,016			481,241
Other operating costs		95,660			85,870
Provision for depreciation		27,971			25,103
Amortization of regulatory assets, net		69,448			86,831
General taxes		16,436			17,496
Total expenses		623,531			696,541
OPERATING INCOME		80,213			77,110
OTHER INCOME (EXPENSE):
Miscellaneous income		1,833			805
Interest expense		(29,423	)		(27,868	)
Capitalized interest		133			62
Total other expense		(27,457	)		(27,001	)
INCOME BEFORE INCOME TAXES		52,756			50,109
INCOME TAXES		23,530			22,551
NET INCOME		29,226			27,558
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		15,928			4,121
Unrealized gain on derivative hedges		69			69
Other comprehensive income		15,997			4,190
Income tax expense related to other comprehensive income		6,558			1,430
Other comprehensive income, net of tax		9,439			2,760
TOTAL COMPREHENSIVE INCOME	$	38,665		$	30,318
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

17

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

18

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	29,226		$	27,558
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		27,971			25,103
Amortization of regulatory assets, net		69,448			86,831
Deferred purchased power and other costs		(32,775	)		(28,369	)
Deferred income taxes and investment tax credits, net		(2,082	)		(6,408	)
Accrued compensation and retirement benefits		(5,847	)		(7,481	)
Cash collateral returned to suppliers		(23,400	)		(209	)
Decrease in operating assets:
Receivables		33,257			27,143
Prepayments and other current assets		16,472			4,792
Increase (decrease) in operating liabilities:
Accounts payable		(40,992	)		(30,029	)
Accrued taxes		50,857			33,114
Accrued interest		11,816			21,249
Tax collections payable		14,544			5,935
Other		466			1,955
Net cash provided from operating activities		148,961			161,184
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			299,619
Redemptions and Repayments-
Common stock		-			(150,000	)
Long-term debt		(6,773	)		(6,402	)
Short-term borrowings, net		-			(121,380	)
Dividend Payments-
Common stock		(90,000	)		(63,000	)
Other		-			(2,152	)
Net cash used for financing activities		(96,773	)		(43,315	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(37,338	)		(37,372	)
Loans to associated companies, net		(7,620	)		(75,108	)
Sales of investment securities held in trusts		190,198			115,483
Purchases of investment securities held in trusts		(194,748	)		(120,062	)
Other		(2,706	)		(872	)
Net cash used for investing activities		(52,214	)		(117,931	)
Net change in cash and cash equivalents		(26	)		(62	)
Cash and cash equivalents at beginning of period		27			66
Cash and cash equivalents at end of period	$	1		$	4
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

19

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In thousands)
REVENUES:
Electric sales	$	451,560		$	409,686
Gross receipts tax collections		21,567			19,983
Total revenues		473,127			429,669
EXPENSES:
Purchased power from affiliates		161,080			100,077
Purchased power from non-affiliates		91,928			123,911
Other operating costs		101,983			106,357
Provision for depreciation		12,758			12,139
Amortization of regulatory assets, net		48,800			27,591
General taxes		21,740			21,935
Total expenses		438,289			392,010
OPERATING INCOME		34,838			37,659
OTHER INCOME (EXPENSE):
Interest income		1,217			3,186
Miscellaneous income		2,173			856
Interest expense		(13,773	)		(13,359	)
Capitalized interest		126			15
Total other expense		(10,257	)		(9,302	)
INCOME BEFORE INCOME TAXES		24,581			28,357
INCOME TAXES		12,266			11,735
NET INCOME		12,315			16,622
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		9,709			4,553
Unrealized gain on derivative hedges		84			84
Other comprehensive income		9,793			4,637
Income tax expense related to other comprehensive income		4,177			1,793
Other comprehensive income, net of tax		5,616			2,844
TOTAL COMPREHENSIVE INCOME	$	17,931		$	19,466
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these
financial statements.

20

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

21

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	12,315		$	16,622
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		12,758			12,139
Amortization of regulatory assets, net		48,800			27,591
Deferred costs recoverable as regulatory assets		(18,276	)		(19,633	)
Deferred income taxes and investment tax credits, net		(10,308	)		4,657
Accrued compensation and retirement benefits		(2,527	)		1,029
Cash collateral to suppliers		(700	)		(9,500	)
Increase in operating assets-
Receivables		(5,083	)		(9,860	)
Prepayments and other current assets		(52,040	)		(50,422	)
Increase (decrease) in operating liabilities-
Accounts payable		(7,279	)		(8,058	)
Accrued taxes		19,960			(7,749	)
Accrued interest		(5,674	)		4,803
Other		2,373			2,460
Net cash used for operating activities		(5,681	)		(35,921	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			300,000
Short-term borrowings, net		48,793			-
Redemptions and Repayments-
Long-term debt		(100,000	)		-
Short-term borrowings, net		-			(15,003	)
Other		-			(2,150	)
Net cash provided from (used for) financing activities		(51,207	)		282,847
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(25,526	)		(25,922	)
Sales of investment securities held in trusts		143,713			27,800
Purchases of investment securities held in trusts		(146,056	)		(29,821	)
Loan repayments from (loans to) associated companies, net		85,383			(218,168	)
Other		(618	)		(832	)
Net cash provided from (used for) investing activities		56,896			(246,943	)
Net increase (decrease) in cash and cash equivalents		8			(17	)
Cash and cash equivalents at beginning of period		120			144
Cash and cash equivalents at end of period	$	128		$	127
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these
financial statements.

22

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In thousands)
REVENUES:
Electric sales	$	385,936		$	371,293
Gross receipts tax collections		17,524			17,292
Total revenues		403,460			388,585
EXPENSES:
Purchased power from affiliates		168,400			96,081
Purchased power from non-affiliates		91,423			127,166
Other operating costs		72,394			77,289
Provision for depreciation		14,682			14,455
Amortization (deferral) of regulatory assets, net		(9,966	)		8,776
General taxes		16,534			20,593
Total expenses		353,467			344,360
OPERATING INCOME		49,993			44,225
OTHER INCOME (EXPENSE):
Miscellaneous income		1,613			798
Interest expense		(17,290	)		(13,233	)
Capitalized interest		140			22
Total other expense		(15,537	)		(12,413	)
INCOME BEFORE INCOME TAXES		34,456			31,812
INCOME TAXES		17,157			13,122
NET INCOME		17,299			18,690
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		8,547			2,955
Unrealized gain on derivative hedges		16			16
Change in unrealized gain on available-for-sale securities		-			(22	)
Other comprehensive income		8,563			2,949
Income tax expense related to other comprehensive income		3,284			1,055
Other comprehensive income, net of tax		5,279			1,894
TOTAL COMPREHENSIVE INCOME	$	22,578		$	20,584
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

23

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2010			2009
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	12		$	14
Receivables-
Customers (less accumulated provisions of $3,768,000 and $3,483,000,
respectively, for uncollectible accounts)		138,010			139,302
Associated companies		92,197			77,338
Other		14,696			18,320
Notes receivable from associated companies		14,311			14,589
Prepaid taxes		69,403			18,946
Other		1,128			1,400
		329,757			269,909
UTILITY PLANT:
In service		2,453,558			2,431,737
Less - Accumulated provision for depreciation		908,550			901,990
		1,545,008			1,529,747
Construction work in progress		22,966			24,205
		1,567,974			1,553,952
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		147,757			142,603
Non-utility generation trusts		120,764			120,070
Other		287			289
		268,808			262,962
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		768,628			768,628
Regulatory assets		119,483			9,045
Power purchase contract asset		5,456			15,362
Other		17,447			19,143
		911,014			812,178
	$	3,077,553		$	2,899,001
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	69,310		$	69,310
Short-term borrowings-
Associated companies		92,807			41,473
Accounts payable-
Associated companies		56,911			39,884
Other		23,680			41,990
Accrued taxes		4,267			6,409
Accrued interest		24,480			17,598
Other		23,300			22,741
		294,755			239,405
CAPITALIZATION:
Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
4,427,577 shares outstanding		88,552			88,552
Other paid-in capital		913,403			913,437
Accumulated other comprehensive loss		(156,825	)		(162,104	)
Retained earnings		108,800			91,501
Total common stockholder's equity		953,930			931,386
Long-term debt and other long-term obligations		1,072,190			1,072,181
		2,026,120			2,003,567
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		274,846			242,040
Retirement benefits		166,509			174,306
Asset retirement obligations		93,374			91,841
Power purchase contract liability		171,244			100,849
Other		50,705			46,993
		756,678			656,029
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	3,077,553		$	2,899,001
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

24

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31
	2010			2009
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	17,299		$	18,690
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		14,682			14,455
Amortization (deferral) of regulatory assets, net		(9,966	)		8,776
Deferred costs recoverable as regulatory assets		(20,461	)		(20,022	)
Deferred income taxes and investment tax credits, net		21,772			11,833
Accrued compensation and retirement benefits		(169	)		431
Cash collateral		(400	)		-
Increase in operating assets-
Receivables		(4,641	)		(1,709	)
Prepayments and other current assets		(50,186	)		(49,707	)
Increase (Decrease) in operating liabilities-
Accounts payable		(1,348	)		(5,340	)
Accrued taxes		(2,142	)		(9,065	)
Accrued interest		6,882			599
Other		7,162			(988	)
Net cash used for operating activities		(21,516	)		(32,047	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		51,334			80,632
Dividend Payments-
Common stock		-			(15,000	)
Other		(6	)		-
Net cash provided from financing activities		51,328			65,632
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(27,388	)		(28,190	)
Sales of investment securities held in trusts		93,057			18,800
Purchases of investment securities held in trusts		(94,464	)		(22,108	)
Loan repayments to associated companies, net		279			(365	)
Other		(1,298	)		(1,732	)
Net cash used for investing activities		(29,814	)		(33,595	)
Net change in cash and cash equivalents		(2	)		(10	)
Cash and cash equivalents at beginning of period		14			23
Cash and cash equivalents at end of period	$	12		$	13
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

25

COMBINED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

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

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

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2009 for FirstEnergy, FES and the Utilities, as applicable. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utilities reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

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

2.  EARNINGS PER SHARE

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

	Three Months Ended
Reconciliation of Basic and Diluted Earnings per Share	March 31
of Common Stock	2010		2009
	(In millions, except per share amounts)
Earnings available to FirstEnergy Corp.	$	155	$	119
Weighted average number of basic shares outstanding		304		304
Assumed exercise of dilutive stock options and awards		2		2
Weighted average number of diluted shares outstanding		306		306
Basic earnings per share of common stock	$	0.51	$	0.39
Diluted earnings per share of common stock	$	0.51	$	0.39

26

3.  FAIR VALUE OF FINANCIAL INSTRUMENTS

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

All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value, in the caption "short-term borrowings." The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations as of March 31, 2010 and December 31, 2009:

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

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

(B) INVESTMENTS

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

Available-For-Sale Securities

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

	March 31, 2010(1)								December 31, 2009(2)
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
Debt securities	(In millions)
FirstEnergy	$	1,741	$	23	$	-	$	1,764	$	1,727	$	22	$	-	$	1,749
FES		1,052		8		-		1,060		1,043		3		-		1,046
OE		55		-		-		55		55		-		-		55
TE		72		-		-		72		72		-		-		72
JCP&L		264		8		-		272		271		9		-		280
Met-Ed		127		3		-		130		120		5		-		125
Penelec		171		4		-		175		166		5		-		171
Equity securities
FirstEnergy	$	268	$	42	$	-	$	310	$	252	$	43	$	-	$	295
FES		-		-		-		-		-		-		-		-
OE		-		-		-		-		-		-		-		-
JCP&L		80		9		-		89		74		11		-		85
Met-Ed		125		22		-		147		117		23		-		140
Penelec		63		11		-		74		61		9		-		70
(1) Excludes cash balances:  FirstEnergy - $131 million; FES -  $32 million; OE - $65 million; TE - $1 million; JCP&L - $15 million; Met-Ed - $(2) million and Penelec - $20 million. (2) Excludes cash balances: FirstEnergy - $137 million; FES - $43 million; OE - $66 million; TE - $2 million; JCP&L - $3 million and Penelec - $23million.

27

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

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

Held-To-Maturity Securities

The following table provides the amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities as of March 31, 2010 and December 31, 2009 (excluding emission allowances, employee benefits, cost method investments and equity method investments of $251 million and $264 million, respectively, that are not required to be disclosed):

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

Notes Receivable

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

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

The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. The maturity dates range from 2010 to 2040.

(C) RECURRING FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

	Recurring Fair Value Measures as of March 31, 2010
	Level 1
Assets		FirstEnergy		FES		TE		OE		JCP&L		Met-Ed		Penelec
Nuclear Decommissioning Trust Investments
Equity securities - consumer products	$	136	$	-	$	-	$	-	$	39	$	65	$	32
Equity securities - technology		59		-		-		-		17		28		14
Equity securities - utilities & energy		59		-		-		-		17		28		14
Equity securities - financial		48		-		-		-		14		23		11
Equity securities - other		8		-		-		-		2		3		3
Total nuclear decommissioning trust  investments	$	310	$	-	$	-	$	-	$	89	$	147	$	74
Total assets(1)	$	310	$	-	$	-	$	-	$	89	$	147	$	74
Liabilities
Derivatives – commodity contracts	$	8	$	8	$	-	$	-	$	-	$	-	$	-
Total liabilities	$	8	$	8	$	-	$	-	$	-	$	-	$	-

29

	Level 2
Assets		FirstEnergy		FES		TE		OE		JCP&L		Met-Ed		Penelec
Nuclear Decommissioning Trust Investments
Debt securities issued by the U.S. government	$	595	$	345	$	66	$	56	$	32	$	88	$	8
Debt securities issued by states of the U.S.		90		-		-		-		30		1		59
Debt securities issued by foreign governments		299		299		-		-		-		-		-
Corporate debt securities		486		413		7		-		21		39		6
Other		90		23		-		65		1		-		1
Total nuclear decommissioning trust investments	$	1,560	$	1,080	$	73	$	121	$	84	$	128	$	74
Rabbi Trust Investments
Equity securities - financial	$	1	$	-	$	-	$	-	$	-	$	-	$	-
Other		11		-		-		1		-		-		-
Total rabbi trust investments	$	12	$	-	$	-	$	1	$	-	$	-	$	-
Nuclear Fuel Disposal Trust Investments
Debt securities issued by states of the U.S.	$	201	$	-	$	-	$	-	$	201	$	-	$	-
Other		2		-		-		-		2		-		-
Total nuclear fuel disposal trust investments	$	203	$	-	$	-	$	-	$	203	$	-	$	-
NUG Trust Investments
Debt securities issued by states of the U.S.	$	98	$	-	$	-	$	-	$	-	$	-	$	98
Other		23		-		-		-		-		-		23
Total NUGtrust investments	$	121	$	-	$	-	$	-	$	-	$	-	$	121
Derivatives
Commodity contracts	$	69	$	60	$	-	$	-	$	2	$	5	$	2
Interest rate contracts		2		-		-		-		-		-
Total Derivatives	$	71	$	60	$	-	$	-	$	2	$	5	$	2
Total assets(1)	$	1,967	$	1,140	$	73	$	122	$	289	$	133	$	197
Liabilities
Derivatives
Commodity contracts	$	296	$	296	$	-	$	-	$	-	$	-	$	-
Interest rate contracts		5		-		-		-		-		-
Total Derivatives	$	301	$	296	$	-	$	-	$	-	$	-	$	-
Total liabilities	$	301	$	296	$	-	$	-	$	-	$	-	$	-

	Level 3
Assets		FirstEnergy		FES		TE		OE		JCP&L		Met-Ed		Penelec
Derivatives – NUG contracts(2)	$	148	$	-	$	-	$	-	$	6	$	137	$	5
Liabilities
Derivatives – NUG contracts(2)	$	738	$	-	$	-	$	-	$	400	$	167	$	171

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

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

30

	Recurring Fair Value Measures as of December 31, 2009
	Level 1
Assets		FirstEnergy		FES		TE		OE		JCP&L		Met-Ed		Penelec
Nuclear Decommissioning Trust Investments
Equity securities - consumer products	$	130	$	-	$	-	$	-	$	38	$	59	$	33
Equity securities - technology		57		-		-		-		17		26		14
Equity securities - utilities & energy		59		-		-		-		17		27		15
Equity securities - financial		39		-		-		-		12		17		10
Equity securities - other		9		-		-		-		3		4		2
Total nuclear decommissioning trust  investments(1)	$	294	$	-	$	-	$	-	$	87	$	133	$	74
Total assets	$	294	$	-	$	-	$	-	$	87	$	133	$	74
Liabilities
Derivatives – commodity contracts	$	11	$	11	$	-	$	-	$	-	$	-	$	-
Total liabilities	$	11	$	11	$	-	$	-	$	-	$	-	$	-

	Level 2
Assets		FirstEnergy		FES		TE		OE		JCP&L		Met-Ed		Penelec
Nuclear Decommissioning Trust Investments
Debt securities issued by the U.S. government	$	558	$	306	$	72	$	118	$	23	$	30	$	9
Debt securities issued by states of the U.S.		188		15		-		-		41		82		50
Debt securities issued by foreign governments		279		279		-		-		-		-		-
Corporate debt securities		484		443		-		-		15		20		6
Other		35		29		-		2		1		2		1
Total nuclear decommissioning trust investments	$	1,544	$	1,072	$	72	$	120	$	80	$	134	$	66
Rabbi Trust Investments
Equity securities - financial	$	1	$	-	$	-	$	-	$	-	$	-	$	-
Other		9		-		-		-		-		-		-
Total rabbi trust investments	$	10	$	-	$	-	$	-	$	-	$	-	$	-
Nuclear Fuel Disposal Trust Investments
Debt securities issued by states of the U.S.	$	189	$	-	$	-	$	-	$	189	$	-	$	-
Other		11		-		-		-		11		-		-
Total nuclear fuel disposal trust investments	$	200	$	-	$	-	$	-	$	200	$	-	$	-
NUG Trust Investments
Debt securities issued by states of the U.S.	$	101	$	-	$	-	$	-	$	-	$	-	$	101
Other		19		-		-		-		-		-		19
Total NUGtrust investments	$	120	$	-	$	-	$	-	$	-	$	-	$	120
Derivatives – commodity contracts	$	34	$	15	$	-	$	-	$	5	$	9	$	5
Other		1		-		-		-		-		-		-
Total assets(1)	$	1,909	$	1,087	$	72	$	120	$	285	$	143	$	191
Liabilities
Derivatives – commodity contracts	$	224	$	224	$	-	$	-	$	-	$	-	$	-
Total Liabilities	$	224	$	224	$	-	$	-	$	-	$	-	$	-

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

31

	Level 3
Assets		FirstEnergy		FES		TE		OE		JCP&L		Met-Ed		Penelec
Derivatives – NUG contracts(2)	$	200	$	-	$	-	$	-	$	9	$	176	$	15
Liabilities
Derivatives – NUG contracts(2)	$	643	$	-	$	-	$	-	$	399	$	143	$	101

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

The determination of the above fair value measures takes into consideration various factors. These factors include nonperformance risk, including counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of nonperformance risk was immaterial in the fair value measurements.

The following tables set forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2010 and 2009 (in millions):

	FirstEnergy			JCP&L			Met-Ed			Penelec
Balance as of January 1, 2010	$	(444	)	$	(391	)	$	33		$	(86	)
Settlements(1)		78			40			17			21
Unrealized losses(1)		(224	)		(43	)		(80	)		(101	)
Balance as of March 31, 2010	$	(590	)	$	(394	)	$	(30	)	$	(166	)
Balance as of January 1, 2009	$	(332	)	$	(518	)	$	150		$	36
Settlements(1)		83			45			17			21
Unrealized gains(1)		(227	)		(45	)		(91	)		(91	)
Balance as of March 31, 2009	$	(476	)	$	(518	)	$	76		$	(34	)

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

4. DERIVATIVE INSTRUMENTS

FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used for risk management purposes. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practices.

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

Cash Flow Hedges

FirstEnergy used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first three months of 2010, FirstEnergy terminated forward swaps with a notional value of $100 million. The termination of the forward starting swap agreements did not materially impact FirstEnergy’s net income and no forward starting swap agreements were outstanding as of March 31, 2010.

32

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

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

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

Fair Value Hedges

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

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

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

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

Commodity Derivatives

FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances where the hedging relationship does not qualify for hedge accounting.

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

Derivative Assets					Derivative Liabilities
		Fair Value					Fair Value
		March 31		December 31			March 31		December 31
		2010		2009			2010		2009
Cash Flow Hedges		(In millions)			Cash Flow Hedges		(In millions)
Electricity Forwards					Electricity Forwards
Current Assets	$	39	$	3	Current Liabilities	$	39	$	7
Noncurrent Assets		19		11	Noncurrent Liabilities		26		12
Natural Gas Futures					Natural Gas Futures
Current Assets		-		-	Current Liabilities		7		9
Noncurrent Assets		-		-	Noncurrent Liabilities		-		-
Other					Other
Current Assets		-		-	Current Liabilities		1		2
Noncurrent Assets		-		-	Noncurrent Liabilities		-		-
	$	58	$	14		$	73	$	30
Derivative Assets					Derivative Liabilities
		Fair Value					Fair Value
		March 31 2010		December 31 2009			March 31 2010		December 31 2009
Economic Hedges		(In millions)			Economic Hedges		(In millions)
NUG Contracts					NUG Contracts
Power Purchase					Power Purchase
Contract Asset	$	148	$	200	Contract Liability	$	738	$	643
Other					Other
Current Assets		1		-	Current Liabilities		139		106
Noncurrent Assets		10		19	Noncurrent Liabilities		92		97
	$	159	$	219		$	969	$	846
Total Commodity Derivatives	$	217	$	233	Total Commodity Derivatives	$	1,042	$	876

Electricity forwards are used to balance expected retail and wholesale sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas, primarily used in FirstEnergy’s peaking units. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s coal transportation contracts. Derivative instruments are not used in quantities greater than forecasted needs. The following table summarizes the volume of FirstEnergy’s outstanding derivative transactions as of March 31, 2010:

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

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

		Three Months Ended March 31,
Derivatives in Cash Flow Hedging Relationships		Electricity			Natural Gas			Heating Oil
		Forwards			Futures			Futures			Total
2010		(in millions)
Gain (Loss) Recognized in AOCL (Effective Portion)	$	(5	)	$	(1	)	$	-		$	(6	)
Effective Gain (Loss) Reclassified to:(1)
Purchased Power Expense		(4	)		-			-			(4	)
Fuel Expense		-			(3	)		(1	)		(4	)
2009
Gain (Loss) Recognized in AOCL (Effective Portion)	$	(2	)	$	(7	)	$	(1	)	$	(10	)
Effective Gain (Loss) Reclassified to:(1)
Purchased Power Expense		(18	)		-			-			(18	)
Fuel Expense		-			-			(4	)		(4	)
(1)  The ineffective portion was immaterial.

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		Three Months Ended March 31,
Derivatives Not in Hedging Relationships			NUG
			Contracts			Other			Total
2010			(In millions)
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense		$	-		$	(52	)	$	(52	)
Regulatory Assets(2)			(224	)		-			(224	)
		$	(224	)	$	(52	)	$	(276	)
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		$	-		$	(25	)	$	(25	)
Regulatory Assets(2)			(78	)		9			(69	)
		$	(78	)	$	(16	)	$	(94	)
2009
Unrealized Gain (Loss) Recognized in:
Regulatory Assets(2)		$	(227	)	$	-		$	(227	)
Realized Gain (Loss) Reclassified to:
Fuel Expense(1)		$	-		$	(1	)	$	(1	)
Regulatory Assets(2)			(83	)		10			(73	)
		$	(83	)	$	9		$	(74	)
(1)	The realized gain (loss) is reclassified upon termination of the derivative instrument.
(2)	Changes in the fair value of NUG contracts are deferred for future recovery from (or refund to) customers.

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

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

5. PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels.

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

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

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

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

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

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

6. VARIABLE INTEREST ENTITIES

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

FirstEnergy’s consolidated financial statements include the accounts of entities in which it has a controlling financial interest. FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest within the consolidated balance sheets is the result of net losses of the noncontrolling interests ($6 million) and distributions to owners ($3 million).

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

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

Power Purchase Agreements

FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Utilities and the contract price for power is correlated with the plant's variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains 20 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

FirstEnergy has determined that for all but two of these entities, neither JCP&L, nor Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of consolidation consideration for VIEs. JCP&L may hold variable interests in the remaining two entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. However, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.

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

Loss Contingencies

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

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

	Maximum Exposure		Discounted Lease Payments, net(1)		Net Exposure
	(In millions)
FES	$	1,372	$	1,195	$	177
OE	702		538		164
CEI(2)	702		69		633
TE(2)	702		385		317

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

(2)   CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements.

7. INCOME TAXES

FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Accounting guidance prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company's tax return. After reaching a tentative agreement with the IRS on a tax item at appeals related to the capitalization of certain costs, FirstEnergy reduced the amount of unrecognized tax benefits by $57 million, with a corresponding adjustment to accumulated deferred income taxes for this temporary tax item. There was no impact on FirstEnergy’s effective tax rate for this tax item for the first three months of 2010. Upon completion of the federal tax examination for the 2007 tax year in the first quarter of 2009, FirstEnergy recognized $13 million in tax benefits, which favorably affected FirstEnergy's effective tax rate.

As of March 31, 2010, it is reasonably possible that approximately $107 million of the unrecognized benefits may be resolved within the next twelve months, of which approximately $12 million, if recognized, would affect FirstEnergy's effective tax rate. The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs, gains and losses recognized on the disposition of assets and various other tax items.

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The Company recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. The reversal of accrued interest associated with the $57 million in recognized tax benefits in 2010 favorably affected FirstEnergy’s effective tax rate by $5 million in the first quarter of 2010. During the first three months of 2009, there were no material changes to the amount of interest accrued. The net amount of accumulated interest accrued as of March 31, 2010 was $20million, as compared to $21 million as of December 31, 2009.

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

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2008. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items were under appeal. In the fourth quarter of 2009, these items were settled at appeals and sent to Joint Committee on Taxation for final review. The federal audits for years 2004-2006 were completed in the third quarter of 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 under its Compliance Assurance Process program and was completed in the first quarter of 2009 with two items under appeal. The IRS began auditing the year 2008 in February 2008 and the audit is expected to close before December 2010. The 2009 tax year audit began in February 2009 and the 2010 tax year began in February 2010. Neither audit is expected to close before December 2010. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

8. COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A) GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of March 31, 2010, outstanding guarantees and other assurances aggregated approximately $4.0 billion, consisting primarily of parental guarantees ($1.0billion), subsidiaries’ guarantees ($2.6 billion), surety bonds and LOCs ($0.4 billion).

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.3 billion (included in the $1.0 billion discussed above) as of March 31, 2010 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of a LOC or accelerated payments may be required of the subsidiary. On February 11, 2010, S&P issued a report lowering FirstEnergy’s and its subsidiaries’ credit ratings by one notch, while maintaining its stable outlook. As a result, FirstEnergy was required to post $46 million of collateral. Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries. As of March 31, 2010, FirstEnergy's maximum exposure under these collateral provisions was $428 million, consisting of $37 million due to “material adverse event” contractual clauses, $63 million due to an acceleration of payment or funding obligation, and $328million due to a below investment grade credit rating that includes the $46 million related to the credit rating downgrade by S&P. Additionally, stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase this amount to $656 million, consisting of $38 million due to “material adverse event” contractual clauses, $63 million related to an acceleration of payment or funding obligation, and $555 million due to a below investment grade credit rating.

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Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $77 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ power portfolio as of March 31, 2010, and forward prices as of that date, FES has posted collateral of $270 million. Under a hypothetical adverse change in forward prices (95% confidence level change in forward prices over a one year time horizon), FES would be required to post an additional $168 million. Depending on the volume of forward contracts and future price movements, FES could be required to post higher amounts for margining.

In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in an amount up to $500 million. The Surplus Margin Guaranty is secured by an NGC FMB issued in favor of the Ohio Companies.

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

(B)ENVIRONMENTAL MATTERS

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

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

Clean Air Act Compliance

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

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

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $399 million for 2010-2012.

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In October 2007, PennFuture and three of its members filed a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations, in the U.S. District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the three complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 16, 2009, a settlement reached with PennFuture and one of the three individual complainants was approved by the Court, which dismissed the claims of PennFuture and of the settling individual. The other two non-settling individuals are now represented by counsel handling the three cases filed in July 2008. FGCO believes those claims are without merit and intends to defend itself against the allegations made in those three complaints. The Pennsylvania Department of Health, under a Cooperative Agreement with the Agency for Toxic Substances and Disease Registry, completed a Health Consultation regarding the Mansfield Plant and issued a report dated March 31, 2009, which concluded there is insufficient sampling data to determine if any public health threat exists for area residents due to emissions from the Mansfield Plant. The report recommended additional air monitoring and sample analysis in the vicinity of the Mansfield Plant, which the Pennsylvania Department of Environmental Protection has completed.

In December 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU and Met-Ed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allege that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint in February and September of 2009, respectively. The Court granted Met-Ed's motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties on statute of limitations grounds in order to allow the states to prove either that the application of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.

In January 2009, the EPA issued a NOV to Reliant alleging NSR violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 2009, NOV also alleged NSR violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of the Keystone Station, and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.

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

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

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

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National Ambient Air Quality Standards

In March 2005, the EPA finalized CAIR, covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia, based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOX emissions to 1.3 million tons annually. CAIR was challenged in the U.S. Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In September 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. On July 10, 2009, the U.S. Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the "8-hour" ozone NAAQS. FGCO's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

Hazardous Air Pollutant Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the U.S. Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire Court, which denied the petition in May 2008. In October 2008, the EPA (and an industry group) petitioned the U.S. Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. On April 15, 2010, the EPA entered into a consent decree requiring it to propose maximum achievable control technology (MACT) regulations for mercury and other hazardous air pollutants by March 16, 2011, and to finalize the regulations by November 16, 2011. On April 29, 2010, the EPA issued proposed MACT regulations requiring emissions reductions of mercury and other hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels such as the proposed Burger biomass repowering project. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards applicable to electric generating units. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’s operations may result.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On December 23, 2009, the Supreme Court of Pennsylvania affirmed the Commonwealth Court of Pennsylvania ruling that Pennsylvania’s mercury rule is “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries. The U.S. signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the U.S. Senate. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050.

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There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, the December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement which recognized the scientific view that the increase in global temperature should be below two degrees Celsius, included a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020, and established the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. Once they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia, and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China, and India, would agree to take mitigation actions, subject to their domestic measurement, reporting, and verification. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the U.S. Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. Also in September 2009, the EPA proposed new thresholds for GHG emissions that define when CAA permits under the NSR and Title V operating permits programs would be required. The EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. The EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that concentrations of several key GHG increase the threat of climate change. In April 2010, EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles requiring an estimated combined average emissions level of 250 grams of CO2 per mile in model year 2016 and clarified that GHG regulation under the CAA will not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest.

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

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

Clean Water Act

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

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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 U.S. Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit Court’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. The EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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

Regulation of Waste Disposal

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including regulation as non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion residuals. In December 2009, the EPA provided to FGCO the findings of its review of the Bruce Mansfield Plant’s coal combustion residuals management practices. The EPA observed that the waste management structures and the Plant “appeared to be well maintained and in good working order” and recommended only that FGCO “seal and maintain all asphalt surfaces.” On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA issued a proposed rule that provides two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FGCO's future cost of compliance with any coal combustion residuals regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.

The Utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of March  31, 2010, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $101 million (JCP&L - $74 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy - $24 million) have been accrued through March 31, 2010. Included in the total are accrued liabilities of approximately $67 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

(C) OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages.

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After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. On March 31, 2009, the trial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was granted by the Appellate Division on June 15, 2009. Plaintiffs filed their appellate brief on August 25, 2009, and JCP&L filed an opposition brief on September 25, 2009. On or about October 13, 2009, Plaintiffs filed their reply brief in further support of their appeal of the trial court's decision decertifying the class. The Appellate Division heard oral argument on January 5, 2010, before a three-judge panel. JCP&L is awaiting the Court’s decision.

Litigation Relating to the Proposed Allegheny Energy Merger

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

Nuclear Plant Matters

Davis Besse Control Rod Drive Mechanism Nozzles

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

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

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

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

Other Legal Matters

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

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009. The parties participated in the federal court's mediation programs and held private settlement discussions. On April 14, 2010, the parties reached a tentative agreement on a settlement package that must be reviewed and approved by the court. JCP&L recognized a liability for the potential $16 million award in 2005, which has been adjusted for post-judgment interest that began to accrue as of February 25, 2009.

On February 16, 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was approved by the PUCO. On March 18, 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas. The court has not yet ruled on that motion to dismiss. The named-defendant companies will continue to defend these claims including challenging any class certification.

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

9. REGULATORY MATTERS

(A) RELIABILITY INITIATIVES

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

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

In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the Midwest ISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards. FirstEnergy’s MISO facilities are next due for the periodic audit by ReliabilityFirst later this year.

On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation required JCP&L to respond to the NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviews with personnel involved in responding to the event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L replied as requested on August 6, 2009. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittals or interview results.

On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays (out of approximately 20,000 reportable relays) in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. ReliabilityFirst issued an Initial Notice of Alleged Violation on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 2009, and submitted it to the FERC for approval on August 19, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-reported violation.

(B) OHIO

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing. On January 21, 2009, the PUCO granted the Ohio Companies’ application in part to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.

SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter. The PUCO has not yet issued a substantive Entry on Rehearing. The ESP proposed by the Ohio Companies was approved by the PUCO on December 19, 2008.  The Ohio Companies thereafter withdrew and terminated the ESP and continued their rate plan then in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider, which recovered the increased purchased power costs for OE and TE, and recovered a portion of those costs for CEI, with the remainder being deferred for future recovery.

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On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP provided that generation would be provided by FES at the average wholesale rate of the CBP described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices would be based upon the outcome of a descending clock CBP on a slice-of-system basis. The Amended ESP further provided that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI would agree to write-off approximately $216 million of its Extended RTC regulatory asset, and that the Ohio Companies would collect a delivery service improvement rider at an overall average rate of $.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressed a number of other issues, including but not limited to, rate design for various customer classes, and resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009.

SB221 also requires electric distribution utilities to implement energy efficiency programs. Under the provisions of SB221, the Ohio Companies are required to achieve a total annual energy savings equivalent of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional .75% reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies have filed an application with the PUCO seeking such amendments. On January 7, 2010, the PUCO amended the 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years. On March 10, 2010, the PUCO found that due to a change in PUCO rules subsequent to the filing of the Ohio Companies’ application, the Ohio Companies’ application seeking a reduction of the peak demand reduction requirements was moot. In its March 10, 2010, Entry the PUCO also found that the Ohio Companies peak demand reduction programs complied with PUCO rules.

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

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

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Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they serve in 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs will be used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On December 7, 2009, the Ohio Companies filed an application with the PUCO seeking a force majeure determination regarding the Ohio Companies’ compliance with the 2009 solar energy resources benchmark, and seeking a reduction in the benchmark. On March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and thus granted the Ohio Companies’ application seeking force majeure. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies’ acquired through their 2009 RFP processes, provided the Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2010, the Ohio Companies and FES (due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy requirements in SB221 for 2009. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark, which application is still pending.

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

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

(C) PENNSYLVANIA

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations.

On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. On August 12, 2009, Met-Ed and Penelec filed a settlement agreement with the PPUC for the generation procurement plan covering the period January 1, 2011, through May 31, 2013, reflecting the settlement on all but two issues. The settlement plan proposes a staggered procurement schedule, which varies by customer class. On September 2, 2009, the ALJ issued a Recommended Decision (RD) approving the settlement and adopted the Met-Ed and Penelec’s positions on two reserved issues. On November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two reserved issues. Generation procurement began in January 2010.

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On May 22, 2008, the PPUC approved Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The TSCs included a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded. On August 11, 2009, the ALJ issued a Recommended Decision to the PPUC approving Met-Ed’s and Penelec’s TSCs as filed and dismissing all complaints. Exceptions by various interveners were filed and reply exceptions were filed by Met-Ed and Penelec. The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which denies the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directs Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructs Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. On March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of marginal transmission loss costs. By Order entered March 25, 2010, the PPUC granted the requested stay until December 31, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of Met-Ed and Penelec that they should prevail in the appeal and therefore expect to fully recover the approximately $199.7 million ($158.5 million for Met-Ed and $41.2 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On April 2, 2010, Met-Ed and Penelec filed a Response to the PPUC’s March 3, 2010 Order requesting approval of procedures to establish separate accounts to track all marginal transmission loss revenues and related interest and the use of those funds to mitigate future generation rate increases commencing January 1, 2011

On May 28, 2009, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2009 through May 31, 2010 subject to the outcome of the proceeding related to the 2008 TSC filing described above, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers the new TSC resulted in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers increased to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, the PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs to a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers would increase approximately 9.4% for the period June 2009 through May 2010.

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

Act 129 also required utilities to file by August 14, 2009 with the PPUC smart meter technology procurement and installation plan to provide for the installation of smart meter technology within 15 years. On August 14, 2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan. Consistent with the PPUC’s rules, this plan proposes a 24-month assessment period in which the Pennsylvania Companies will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs at approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. An Initial Decision was issued by the presiding ALJ on January 28, 2010. The ALJ’s Initial Decision approved the Smart Meter Plan as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; eliminating the provision of interest in the 1307(e) reconciliation; providing for the recovery of reasonable and prudent costs minus resulting savings from installation and use of smart meters; and reflecting that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. On April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision issued on January 28, 2010, and decided various issues regarding the Smart Meter Implementation Plan (SMIP) for the Pennsylvania Companies. An order consistent with Chairman Cawley’s Motion is anticipated to be entered in the near future, in which event the Pennsylvania Companies will move forward with the Smart Meter Technology Procurement and Installation Plan.

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

On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the Pennsylvania Companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings.

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

On February 8, 2010, Penn filed with the PPUC a generation procurement plan covering the period June 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. A preliminary conference was held on March 26, 2010, and, among other things, established a procedural schedule.  Evidentiary hearings are scheduled for June 15-16, 2010. The PPUC is required to issue an order on the plan no later than November 8, 2010.

(D) NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31, 2010, the accumulated deferred cost balance totaled approximately $55 million.

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

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. The EMP was issued on October 22, 2008, establishing five major goals:

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

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

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

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

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

On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by New Jersey electric and gas utilities in order to achieve the goals of the EMP. On April 16, 2010, the BPU issued an order indefinitely suspending the requirement of New Jersey utilities to submit Utility Master Plans until such time as the status of the EMP has been made clear. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations.

In support of former New Jersey Governor Corzine's Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. In addition, approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million would be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent on energy efficiency programs that would complement those currently being offered. The project relating to expansion of the existing demand response programs was approved by the NJBPU on August 19, 2009, and implementation began in 2009. Approval for the project related to energy efficiency programs intended to complement those currently being offered was denied by the NJBPU on December 1, 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal.

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

(E) FERC MATTERS

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements. On October 29, 2009, March 17, 2010 and April 8, 2010, FirstEnergy, filed additional settlement agreements with FERC to resolve outstanding claims with various parties. FirstEnergy is actively pursuing settlement agreements with other parties to the case. On December 8, 2009, certain parties sought a writ of mandamus from the DC Circuit Court of Appeals directing FERC to issue an order on the Initial Decision. The Court agreed to hold this matter in abeyance based upon FERC’s representation to use good faith efforts to issue a substantive ruling on the initial decision no later than May 27, 2010. If FERC fails to act, the case will be submitted for briefing in June. The outcome of this matter cannot be predicted.

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PJM Transmission Rate

On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held on the content of the compliance filings and numerous parties appeared and litigated various issues concerning PJM rate design, notably AEP, which proposed to create a "postage stamp," or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. AEP's proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order (Opinion 494) finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

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

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

RTO Consolidation

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

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

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

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

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

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

Changes ordered for PJM Reliability Pricing Model (RPM) Auction

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

On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. It ordered changes included making incremental improvements to RPM and clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; subsequently, numerous parties filed requests for rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied rehearing and request for oral argument of the March 26, 2009 Order.

MISO Complaints Versus PJM

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

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

53

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

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

10. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

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

11. SEGMENT INFORMATION

Financial information for each of FirstEnergy’s reportable segments is presented in the following table. FES and the Utilities do not have separate reportable operating segments. With the completion of transition to a fully competitive generation market in Ohio in the fourth quarter of 2009, the former Ohio Transitional Generation Services segment was combined with the Energy Delivery Services segment, consistent with how management views the business. Disclosures for FirstEnergy’s operating segments for 2009 have been reclassified to conform to the current presentation.

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

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

54

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

Segment Financial Information
		Energy			Competitive
		Delivery			Energy						Reconciling
Three Months Ended		Services			Services			Other			Adjustments			Consolidated
		(In millions)
March 31, 2010
External revenues		$	2,543		$	716		$	4		$	(31	)	$	3,232
Internal revenues			-			674			-			(607	)		67
	Total revenues		2,543			1,390			4			(638	)		3,299
Depreciation and amortization			325			66			13			1			405
Investment income (loss), net			25			1			-			(10	)		16
Net interest charges			123			33			(1	)		17			172
Income taxes			69			47			4			(9	)		111
Net income (loss)			114			76			(15	)		(26	)		149
Total assets			22,530			10,948			605			(5	)		34,078
Total goodwill			5,551			24			-			-			5,575
Property additions			166			323			3			16			508
March 31, 2009
External revenues		$	3,021		$	335		$	7		$	(29	)	$	3,334
Internal revenues			-			893			-			(893	)		-
	Total revenues		3,021			1,228			7			(922	)		3,334
Depreciation and amortization			427			64			1			3			495
Investment income (loss), net			30			(29	)		-			(12	)		(11	)
Net interest charges			109			18			1			38			166
Income taxes			(12	)		103			(17	)		(20	)		54
Net income			(18	)		155			17			(39	)		115
Total assets			23,005			9,925			632			(5	)		33,557
Total goodwill			5,550			24			-			-			5,574
Property additions			165			421			49			19			654
*	Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for
	sales of RECs by FES to the Ohio Companies that are retained in inventory.

Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses and elimination of intersegment transactions.

12. SUPPLEMENTAL GUARANTOR INFORMATION

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully, unconditionally and irrevocably guaranteed all of FGCO's obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust's undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES' lease guaranty. This transaction is classified as an operating lease under GAAP for FES and FirstEnergy and as a financing for FGCO.

The condensed consolidating statements of income for the three-months ended March 31, 2010 and 2009, consolidating balance sheets as of March 31, 2010 and December 31, 2009 and consolidating statements of cash flows for the three months ended March 31, 2010 and 2009 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES' investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

55

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
For the Three Months Ended March 31, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	1,367,025		$	568,364		$	426,320		$	(973,616	)	$	1,388,093
EXPENSES:
Fuel		5,097			280,863			42,261			-			328,221
Purchased power from affiliates		968,537			5,079			60,953			(973,616	)		60,953
Purchased power from non-affiliates		450,215			-			-			-			450,215
Other operating expenses		53,126			99,776			139,420			12,189			304,511
Provision for depreciation		790			26,527			36,910			(1,309	)		62,918
General taxes		5,498			14,600			6,648			-			26,746
Total expenses		1,483,263			426,845			286,192			(962,736	)		1,233,564
OPERATING INCOME (LOSS)		(116,238	)		141,519			140,128			(10,880	)		154,529
OTHER INCOME (EXPENSE):
Investment income		1,897			54			(1,234	)		-			717
Miscellaneous income (expense), including
net income from equity investees		166,373			(1,633	)		(101	)		(163,329	)		1,310
Interest expense to affiliates		(58	)		(1,812	)		(435	)		-			(2,305	)
Interest expense - other		(23,373	)		(26,506	)		(15,763	)		15,998			(49,644	)
Capitalized interest		100			16,333			3,257			-			19,690
Total other income (expense)		144,939			(13,564	)		(14,276	)		(147,331	)		(30,232	)
INCOME BEFORE INCOME TAXES		28,701			127,955			125,852			(158,211	)		124,297
INCOME TAXES (BENEFITS)		(51,225	)		48,043			45,013			2,540			44,371
NET INCOME	$	79,926		$	79,912		$	80,839		$	(160,751	)	$	79,926

56

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
For the Three Months Ended March 31, 2009	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	1,201,895		$	545,926		$	395,628		$	(917,343	)	$	1,226,106
EXPENSES:
Fuel		2,095			274,847			29,216			-			306,158
Purchased power from affiliates		915,261			2,082			63,207			(917,343	)		63,207
Purchased power from non-affiliates		160,342			-			-			-			160,342
Other operating expenses		38,267			104,443			152,456			12,190			307,356
Provision for depreciation		1,019			30,020			31,649			(1,315	)		61,373
General taxes		4,706			12,626			6,044			-			23,376
Total expenses		1,121,690			424,018			282,572			(906,468	)		921,812
OPERATING INCOME		80,205			121,908			113,056			(10,875	)		304,294
OTHER INCOME (EXPENSE):
Investment income (loss)		732			31			(29,637	)		-			(28,874	)
Miscellaneous income (expense), including
net income from equity investees		119,781			(78	)		-			(117,192	)		2,511
Interest expense to affiliates		(34	)		(1,758	)		(1,187	)		-			(2,979	)
Interest expense - other		(2,520	)		(21,058	)		(15,168	)		16,219			(22,527	)
Capitalized interest		51			7,750			2,277			-			10,078
Total other income (expense)		118,010			(15,113	)		(43,715	)		(100,973	)		(41,791	)
INCOME BEFORE INCOME TAXES		198,215			106,795			69,341			(111,848	)		262,503
INCOME TAXES		27,534			39,142			22,929			2,217			91,822
NET INCOME	$	170,681		$	67,653		$	46,412		$	(114,065	)	$	170,681

57

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of March 31, 2010	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	-	$	2	$	9	$	-		$	11
Receivables-
Customers		248,994		-		-		-			248,994
Associated companies		408,743		199,145		129,194		(376,278	)		360,804
Other		18,732		12,856		50,071		-			81,659
Notes receivable from associated companies		165,496		209,604		108,323		-			483,423
Materials and supplies, at average cost		16,698		327,011		215,042		-			558,751
Prepayments and other		147,780		8,234		4,654		-			160,668
		1,006,443		756,852		507,293		(376,278	)		1,894,310
PROPERTY, PLANT AND EQUIPMENT:
In service		91,365		5,473,440		5,189,224		(386,022	)		10,368,007
Less - Accumulated provision for depreciation		15,030		2,802,155		1,973,499		(172,820	)		4,617,864
		76,335		2,671,285		3,215,725		(213,202	)		5,750,143
Construction work in progress		7,836		2,110,754		479,040		-			2,597,630
		84,171		4,782,039		3,694,765		(213,202	)		8,347,773
INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,091,114		-			1,091,114
Investment in associated companies		4,637,194		-		-		(4,637,194	)		-
Other		957		7,367		201		-			8,525
		4,638,151		7,367		1,091,315		(4,637,194	)		1,099,639
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		88,618		379,772		-		(401,928	)		66,462
Goodwill		24,248		-		-		-			24,248
Customer intangibles		114,567		-		-		-			114,567
Property taxes		-		27,811		22,314		-			50,125
Unamortized sale and leaseback costs		-		29,968		-		60,835			90,803
Other		80,182		71,044		9,188		(50,920	)		109,494
		307,615		508,595		31,502		(392,013	)		455,699
	$	6,036,380	$	6,054,853	$	5,324,875	$	(5,618,687	)	$	11,797,421
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	745	$	696,416	$	922,663	$	(18,640	)	$	1,601,184
Short-term borrowings-
Other		100,000		-		-		-			100,000
Accounts payable-
Associated companies		325,118		194,950		190,103		(324,920	)		385,251
Other		116,942		153,515		-		-			270,457
Accrued taxes		7,719		72,449		48,798		(62,381	)		66,585
Other		213,488		105,682		27,798		46,544			393,512
		764,012		1,223,012		1,189,362		(359,397	)		2,816,989
CAPITALIZATION:
Common stockholder's equity		3,589,580		2,419,526		2,203,491		(4,623,017	)		3,589,580
Long-term debt and other long-term obligations		1,519,155		1,855,784		554,591		(1,269,330	)		2,660,200
		5,108,735		4,275,310		2,758,082		(5,892,347	)		6,249,780
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		984,440			984,440
Accumulated deferred income taxes		-		-		351,383		(351,383	)		-
Accumulated deferred investment tax credits		-		35,590		21,763		-			57,353
Asset retirement obligations		-		25,933		910,520		-			936,453
Retirement benefits		35,114		184,060		-		-			219,174
Property taxes		-		27,811		22,314		-			50,125
Lease market valuation liability		-		250,871		-		-			250,871
Other		128,519		32,266		71,451		-			232,236
		163,633		556,531		1,377,431		633,057			2,730,652
	$	6,036,380	$	6,054,853	$	5,324,875	$	(5,618,687	)	$	11,797,421

58

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of December 31, 2009	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	-	$	3	$	9	$	-		$	12
Receivables-
Customers		195,107		-		-		-			195,107
Associated companies		305,298		175,730		134,841		(297,308	)		318,561
Other		28,394		10,960		12,518		-			51,872
Notes receivable from associated companies		416,404		240,836		147,863		-			805,103
Materials and supplies, at average cost		17,265		307,079		215,197		-			539,541
Prepayments and other		80,025		18,356		9,401		-			107,782
		1,042,493		752,964		519,829		(297,308	)		2,017,978
PROPERTY, PLANT AND EQUIPMENT:
In service		90,474		5,478,346		5,174,835		(386,023	)		10,357,632
Less - Accumulated provision for depreciation		13,649		2,778,320		1,910,701		(171,512	)		4,531,158
		76,825		2,700,026		3,264,134		(214,511	)		5,826,474
Construction work in progress		6,032		2,049,078		368,336		-			2,423,446
		82,857		4,749,104		3,632,470		(214,511	)		8,249,920
INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,088,641		-			1,088,641
Investment in associated companies		4,477,602		-		-		(4,477,602	)		-
Other		1,137		21,127		202		-			22,466
		4,478,739		21,127		1,088,843		(4,477,602	)		1,111,107
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		93,379		381,849		-		(388,602	)		86,626
Goodwill		24,248		-		-		-			24,248
Customer intangibles		16,566		-		-		-			16,566
Property taxes		-		27,811		22,314		-			50,125
Unamortized sale and leaseback costs		-		16,454		-		56,099			72,553
Other		82,845		71,179		18,755		(51,114	)		121,665
		217,038		497,293		41,069		(383,617	)		371,783
	$	5,821,127	$	6,020,488	$	5,282,211	$	(5,373,038	)	$	11,750,788
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	736	$	646,402	$	922,429	$	(18,640	)	$	1,550,927
Short-term borrowings-
Associated companies		-		9,237		-		-			9,237
Other		100,000		-		-		-			100,000
Accounts payable-
Associated companies		261,788		170,446		295,045		(261,201	)		466,078
Other		51,722		193,641		-		-			245,363
Accrued taxes		44,213		61,055		22,777		(44,887	)		83,158
Other		173,015		132,314		16,734		36,994			359,057
		631,474		1,213,095		1,256,985		(287,734	)		2,813,820
CAPITALIZATION:
Common stockholder's equity		3,514,571		2,346,515		2,119,488		(4,466,003	)		3,514,571
Long-term debt and other long-term obligations		1,519,339		1,906,818		554,825		(1,269,330	)		2,711,652
		5,033,910		4,253,333		2,674,313		(5,735,333	)		6,226,223
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		992,869			992,869
Accumulated deferred income taxes		-		-		342,840		(342,840	)		-
Accumulated deferred investment tax credits		-		36,359		22,037		-			58,396
Asset retirement obligations		-		25,714		895,734		-			921,448
Retirement benefits		33,144		170,891		-		-			204,035
Property taxes		-		27,811		22,314		-			50,125
Lease market valuation liability		-		262,200		-		-			262,200
Other		122,599		31,085		67,988		-			221,672
		155,743		554,060		1,350,913		650,029			2,710,745
	$	5,821,127	$	6,020,488	$	5,282,211	$	(5,373,038	)	$	11,750,788

59

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
For the Three Months Ended March 31, 2010	FES			FGCO			NGC			Eliminations		Consolidated
	(In thousands)
NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES	$	(147,718	)	$	40,130		$	98,692		$	-	$	(8,896	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt		(197	)		(1,081	)		-			-		(1,278	)
Short-term borrowings, net		-			(9,237	)		-			-		(9,237	)
Other		(453	)		(177	)		(101	)		-		(731	)
Net cash used for financing activities		(650	)		(10,495	)		(101	)		-		(11,246	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(2,103	)		(174,163	)		(125,337	)		-		(301,603	)
Proceeds from asset sales		-			114,272			-			-		114,272
Sales of investment securities held in trusts		-			-			272,094			-		272,094
Purchases of investment securities held in trusts		-			-			(284,888	)		-		(284,888	)
Loans from associated companies, net		250,908			31,232			39,540			-		321,680
Customer intangibles		(100,615	)		-			-			-		(100,615	)
Other		178			(977	)		-			-		(799	)
Net cash provided from (used for) investing activities		148,368			(29,636	)		(98,591	)		-		20,141
Net change in cash and cash equivalents		-			(1	)		-			-		(1	)
Cash and cash equivalents at beginning of period		-			3			9			-		12
Cash and cash equivalents at end of period	$	-		$	2		$	9		$	-	$	11

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
For the Three Months Ended March 31, 2009	FES			FGCO			NGC			Eliminations		Consolidated
	(In thousands)
NET CASH PROVIDED FROM OPERATING ACTIVITIES	$	200,420		$	28,545		$	118,902		$	-	$	347,867
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			100,000			-			-		100,000
Short-term borrowings, net		98,881			88,308			434,105			-		621,294
Redemptions and Repayments-
Long-term debt		(1,189	)		(626	)		(334,101	)		-		(335,916	)
Net cash provided from financing activities		97,692			187,682			100,004			-		385,378
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(358	)		(198,631	)		(213,816	)		-		(412,805	)
Proceeds from asset sales		-			7,573			-			-		7,573
Sales of investment securities held in trusts		-			-			351,414			-		351,414
Purchases of investment securities held in trusts		-			-			(356,904	)		-		(356,904	)
Loans to associated companies, net		(297,641	)		(6,322	)		-			-		(303,963	)
Other		(113	)		(18,852	)		400			-		(18,565	)
Net cash used for investing activities		(298,112	)		(216,232	)		(218,906	)		-		(733,250	)
Net change in cash and cash equivalents		-			(5	)		-			-		(5	)
Cash and cash equivalents at beginning of period		-			39			-			-		39
Cash and cash equivalents at end of period	$	-		$	34		$	-		$	-	$	34

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13. INTANGIBLE ASSETS

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

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

14. PROPOSED MERGER WITH ALLEGHENY ENERGY, INC.

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

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

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

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

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

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

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

FIRSTENERGY CORP.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

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

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

Financial Matters

Proposed Merger with Allegheny Energy, Inc.

On February 10, 2010, FirstEnergy entered into an Agreement and Plan of  Merger (Merger Agreement) with Element Merger Sub. Inc., a Maryland corporation and its wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into Allegheny Energy with Allegheny Energy continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy.  Pursuant to the Merger Agreement, upon the closing of the merger, each issued and outstanding share of Allegheny Energy common stock, including grants of restricted common stock, will automatically be converted into the right to receive 0.667 of a share of common stock of FirstEnergy and Allegheny Energystockholders will own approximately 27% of the combined company.  Based on the closing stock prices for both companies on February 10, 2010, Allegheny Energy shareholders would receive a value of $27.65 per share, or $4.7 billion in the aggregate. FirstEnergy will also assume all outstanding Allegheny Energy debt. The price per share represents a premium of 31.6% to the closing stock price of Allegheny Energy on February 10, 2010, and a 22.3% premium to the average stock price of Allegheny over the last 60 days ending February 10, 2010.

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

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

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

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

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

Non-core asset sales/Impairments

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

Derivative mark-to-market adjustments

As a result of the continued decline in electricity prices, mark-to-market adjustments relating to certain purchased power contracts increased expenses in the first quarter of 2010 by $51.9 million ($32.5 million after tax). From December 31, 2009 to March 31, 2010 forward around the clock electricity prices per MWH have declined approximately 14%.

Elimination of retiree prescription drug tax benefits

As a result of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law on March 23, 2010 and March 30, 2010, respectively, beginning in 2011 the tax deduction available to FirstEnergy will be reduced to the extent that drug costs are reimbursed under the Medicare Part D retiree subsidy program. During the first quarter of 2010, FirstEnergy recognized a one-time adjustment of approximately $12.6 million to reduce the deferred tax asset associated with these subsidies.

Operational Matters

Davis Besse Refueling

On February 28, 2010, the Davis Besse Nuclear Plant (908-MW)began a refueling outage to exchange 76 of the 177 fuel assemblies and conduct numerous safety inspections. During the outage, it was determined that modifications were needed to 16 of the 69 control rod drive mechanism nozzles (CDRM) that penetrated the reactor vessel head. Further evaluation and testing identified 8 additional nozzles requiring modifications. Additional testing will be conducted following the modification of each nozzle to ensure safe, reliable plant operations. The plant is expected to be ready for restart in July, 2010.

PJM RTO Integration

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

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Regulatory Matters - Ohio

New Electric Security Plan

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

Regulatory Matters - Pennsylvania

Met-Ed and Penelec Transmission Service Charge

On March 3, 2010, Met-Ed and Penelec received an Order from the PPUC which denied the recovery of marginal transmission losses through the TSC rider for the period June 1, 2007 through March 31, 2008 and instructed Met-Ed and Penelec to work with the parties and file a petition to retain any over-collection, with interest, until 2011, when Met-Ed and Penelec’s generation rate caps expire. In response to the Order, on March 18, 2010, Met-Ed and Penelec requested that the PPUC grant a stay of its Order, with such stay being granted by the PPUC on March 25, 2010 until December 31, 2010, allowing for the continued collection of marginal losses subject to refund. On April 1, 2010, Met-Ed and Penelec filed with the Commonwealth Court of Pennsylvania a Petition for Review of the PPUC’s Order disallowing the recovery of marginal transmission losses in the TSC. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penlec believe they should prevail on appeal and should recover marginal transmission losses for the period prior to January 1, 2011.

FIRSTENERGY'S BUSINESS

FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through two core business segments (see Results of Operations).

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

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

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RESULTS OF OPERATIONS

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

	Three Months Ended
	March 31						Increase
	2010			2009			(Decrease)
	(In millions, except per share data)
Earnings By Business Segment:
Energy delivery services	$	114		$	(18	)	$	132
Competitive energy services		76			155			(79	)
Other and reconciling adjustments*		(35	)		(18	)		(17	)
Total	$	155		$	119		$	36
Basic Earnings Per Share	$	0.51		$	0.39		$	0.12
Diluted Earnings Per Share	$	0.51		$	0.39		$	0.12
* Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions.

Summary of Results of Operations – First Quarter 2010 Compared with First Quarter 2009

Financial results for FirstEnergy's major business segments in the first quarter of 2010 and 2009 were as follows:

		Energy			Competitive			Other and
		Delivery			Energy			Reconciling			FirstEnergy
First Quarter 2010 Financial Results		Services			Services			Adjustments			Consolidated
		(In millions)
Revenues:
	External
	Electric	$	2,398		$	669		$	-		$	3,067
	Other		145			47			(27	)		165
	Internal*		-			674			(607	)		67
Total Revenues			2,543			1,390			(634	)		3,299
Expenses:
	Fuel		-			337			(3	)		334
	Purchased power		1,395			450			(607	)		1,238
	Other operating expenses		380			347			(26	)		701
	Provision for depreciation		113			66			14			193
	Amortization of regulatory assets		212			-			-			212
	Deferral of new regulatory assets		-			-			-			-
	General taxes		162			35			8			205
Total Expenses			2,262			1,235			(614	)		2,883
Operating Income			281			155			(20	)		416
Other Income (Expense):
	Investment income		25			1			(10	)		16
	Interest expense		(124	)		(53	)		(36	)		(213	)
	Capitalized interest		1			20			20			41
Total Other Expense			(98	)		(32	)		(26	)		(156	)
Income Before Income Taxes			183			123			(46	)		260
Income taxes			69			47			(5	)		111
Net Income (Loss)			114			76			(41	)		149
Noncontrolling interest loss			-			-			(6	)		(6	)
Earnings available to FirstEnergy Corp.		$	114		$	76		$	(35	)	$	155
*	Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sale of RECs by FES to the Ohio Companies that are retained in inventory.

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	Energy			Competitive			Other and
	Delivery			Energy			Reconciling			FirstEnergy
First Quarter 2009 Financial Results	Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	2,861		$	280		$	-		$	3,141
Other		160			55			(22	)		193
Internal		-			893			(893	)		-
Total Revenues		3,021			1,228			(915	)		3,334
Expenses:
Fuel		-			312			-			312
Purchased power		1,876			160			(893	)		1,143
Other operating expenses		499			355			(27	)		827
Provision for depreciation		109			64			4			177
Amortization of regulatory assets, net		411			-			-			411
Deferral of new regulatory assets		(93	)		-			-			(93	)
General taxes		170			32			9			211
Total Expenses		2,972			923			(907	)		2,988
Operating Income		49			305			(8	)		346
Other Income (Expense):
Investment income		30			(29	)		(12	)		(11	)
Interest expense		(110	)		(28	)		(56	)		(194	)
Capitalized interest		1			10			17			28
Total Other Expense		(79	)		(47	)		(51	)		(177	)
Income Before Income Taxes		(30	)		258			(59	)		169
Income taxes		(12	)		103			(37	)		54
Net Income (Loss)		(18	)		155			(22	)		115
Noncontrolling interest loss		-			-			(4	)		(4	)
Earnings available to FirstEnergy Corp.	$	(18	)	$	155		$	(18	)	$	119
Changes Between First Quarter 2010 and
First Quarter 2009 Financial Results
Increase (Decrease)
Revenues:
External
Electric	$	(463	)	$	389		$	-		$	(74	)
Other		(15	)		(8	)		(5	)		(28	)
Internal		-			(219	)		286			67
Total Revenues		(478	)		162			281			(35	)
Expenses:
Fuel		-			25			(3	)		22
Purchased power		(481	)		290			286			95
Other operating expenses		(119	)		(8	)		1			(126	)
Provision for depreciation		4			2			10			16
Amortization of regulatory assets		(199	)		-			-			(199	)
Deferral of new regulatory assets		93			-			-			93
General taxes		(8	)		3			(1	)		(6	)
Total Expenses		(710	)		312			293			(105	)
Operating Income		232			(150	)		(12	)		70
Other Income (Expense):
Investment income		(5	)		30			2			27
Interest expense		(14	)		(25	)		20			(19	)
Capitalized interest		-			10			3			13
Total Other Expense		(19	)		15			25			21
Income Before Income Taxes		213			(135	)		13			91
Income taxes		81			(56	)		32			57
Net Income (Loss)		132			(79	)		(19	)		34
Noncontrolling interest loss		-			-			(2	)		(2	)
Earnings available to FirstEnergy Corp.	$	132		$	(79	)	$	(17	)	$	36

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

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

Revenues –

The decrease in total revenues resulted from the following sources:

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

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

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

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

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

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

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

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

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

Expenses –

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

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

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

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	187
Change due to decreased volumes		(419	)
		(232	)
Purchases from FES:
Change due to decreased unit costs		(94	)
Change due to decreased volumes		(152	)
		(246	)
Increase in NUG costs deferred		(3	)
Net Decrease in Purchased Power Costs	$	(481	)

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

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

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

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

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

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

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

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

Other Expense –

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

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

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

Revenues –

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

The increase in total revenues resulted from the following sources:

	Three Months
	Ended March 31				Increase
Revenues by Type of Service	2010		2009		(Decrease)
	(In millions)
Direct and Government Aggregation	$	512	$	91	$	421
PLR		677		893		(216	)
Wholesale		87		189		(102	)
Transmission		17		25		(8)
RECs		67		-		67
Other		30		30		-
Total Revenues	$	1,390	$	1,228	$	162

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

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

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

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

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

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

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

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

Expenses -

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

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

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

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

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

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

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

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

Other Expense –

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

Other – First Quarter 2010 Compared with First Quarter 2009

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

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CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy's business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2010 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets as market conditions warrant. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

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

Currently Payable Long-term Debt
PCRBs supported by bank LOCs(1)	$	1,553
FGCO and NGC unsecured PCRBs(1)	65
Penelec FMBs(2)	24
NGC collateralized lease obligation bonds	44
Sinking fund requirements	34
Other notes(2)	63
	$	1,783
(1)  Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity. (2) Mature in November 2010.

Short-Term Borrowings

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

Company	Type	Maturity	Commitment		Available Liquidity as of April 30, 2010
			(In millions)
FirstEnergy(1)	Revolving	Aug. 2012	$	2,750	$	1,380
FirstEnergy Solutions	Bank line	Mar. 2011		100		-
Ohio and Pennsylvania Companies	Receivables financing	Various(2)		345		272
		Subtotal	$	3,195	$	1,652
		Cash		-		357
		Total	$	3,195	$	2,009
(1)FirstEnergy Corp. and subsidiary borrowers. (2)Ohio - $200 million (March – May 2010), $250 million (June 2010 – February 2011) matures March 30, 2011; Pennsylvania -     $145 million matures December 17, 2010

Revolving Credit Facility

FirstEnergy has the capability to request an increase in the total commitments available under the $2.75 billion revolving credit facility (included in the borrowing capability table above) up to a maximum of $3.25 billion, subject to the discretion of each lender to provide additional commitments. A total of 25 banks participate in the facility, with no one bank having more than 7.3% of the total commitment. Commitments under the facility are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.

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The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of March 31, 2010:

	Revolving			Regulatory and
	Credit Facility			Other Short-Term
Borrower	Sub-Limit			Debt Limitations
	(In millions)
FirstEnergy	$	2,750		$	-	(1)
FES		1,000			-	(1)
OE		500			500
Penn		50			33	(2)
CEI		250	(3)		500
TE		250	(3)		500
JCP&L		425			411	(2)
Met-Ed		250			300	(2)
Penelec		250			300	(2)
ATSI		50	(4)		50

(1)  No regulatory approvals, statutory or charter limitations applicable.

(2)  Excluding amounts which may be borrowed under the regulated companies'

     money pool.

(3)  Borrowing sub-limits for CEI and TE may be increased to up to $500 million

     by delivering notice to the administrative agent that such borrower has senior

     unsecured debt ratings of at least BBB by S&P and Baa2 by Moody's.

 (4) The borrowing sub-limit for ATSI may be increased up to $100 million by

     delivering notice to the administrative agent that ATSI has received regulatory

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

Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower's borrowing sub-limit.

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

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

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

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

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

    credit facility.

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

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FirstEnergy Money Pools

FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first three months of 2010 was 0.49% for the regulated companies' money pool and 0.54% for the unregulated companies' money pool.

Pollution Control Revenue Bonds

As of March 31, 2010, FirstEnergy's currently payable long-term debt included approximately $1.6 billion (FES - $1.5 billion, Met-Ed - $29 million and Penelec - $45 million) of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.

The LOCs for FirstEnergy variable interest rate PCRBs were issued by the following banks as of March 31, 2010:

	Aggregate LOC			Reimbursements of
LOC Bank	Amount(3)		LOC Termination Date	LOC Draws Due
	(In millions)
CitiBank N.A.	$	166	June 2014	June 2014
The Bank of Nova Scotia	284		Beginning April 2011	Multiple dates(4)
The Royal Bank of Scotland	131		June 2012	6 months
KeyBank(1)	237		June 2010	6 months
Wachovia Bank	153		March 2014	March 2014
Barclays Bank(2)	528		Beginning December 2010	30 days
PNC Bank	70		Beginning November 2010	180 days
Total	$	1,569
(1)Supported by four participating banks, with the LOC bank having 58% of the total commitment. (2)Supported by 18 participating banks, with no one bank having more than 14% of the total commitment. (3)Includes approximately $16 million of applicable interest coverage. (4)Shorter of 6 months or LOC termination date ($155 million) and shorter of one year or LOC termination date ($129 million).

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

Long-Term Debt Capacity

As of March 31, 2010, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.3 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMBs by the Ohio Companies is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $101 million and $17 million, respectively, as of March 31, 2010. As a result of the indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately $379 million and $345 million, respectively, under provisions of their senior note indentures as of March 31, 2010.

Based upon FGCO's FMB indenture, net earnings and available bondable property additions as of March 31, 2010, FGCO had the capability to issue $2.4 billion of additional FMBs under the terms of that indenture. In June 2009, a new FMB indenture became effective for NGC. Based upon NGC’s FMB indenture, net earnings and available bondable property additions, NGC had the capability to issue $294 million of additional FMBs as of March 31, 2010.

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FirstEnergy's access to capital markets and costs of financing are influenced by the ratings of its securities.  On February 11, 2010, S&P issued a report lowering FirstEnergy’s and its subsidiaries credit ratings by one notch, while maintaining its stable outlook.  Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010.   The following table displays FirstEnergy's, FES' and the Utilities' securities ratings as of March 31, 2010.

Issuer	Senior Secured			Senior Unsecured
	S&P	Moodys	Fitch	S&P	Moodys	Fitch
FirstEnergy Corp.	-	-	-	BB+	Baa3	BBB
FirstEnergy Solutions	-	-	-	BBB-	Baa2	BBB
Ohio Edison	BBB	A3	BBB+	BBB-	Baa2	BBB
Pennsylvania Power	BBB+	A3	BBB+	-	-	-
Cleveland Electric Illuminating	BBB	Baa1	BBB	BBB-	Baa3	BBB-
Toledo Edison	BBB	Baa1	BBB	-	-	-
Jersey Central Power & Light	-	-	-	BBB-	Baa2	BBB+
Metropolitan Edison	BBB	A3	BBB+	BBB-	Baa2	BBB
Pennsylvania Electric	BBB	A3	BBB+	BBB-	Baa2	BBB
ATSI	-	-	-	BBB-	Baa1	-

Changes in Cash Position

As of March 31, 2010, FirstEnergy had $310million in cash and cash equivalents compared to $874 million as of December 31, 2009. As of March 31, 2010 and December 31, 2009, FirstEnergy had approximately $12 million of restricted cash included in other current assets on the Consolidated Balance Sheet.

During the first three months of 2010, FirstEnergy received $620 million of cash dividends from its subsidiaries and paid $168 million in cash dividends to common shareholders.

Cash Flows From Operating Activities

FirstEnergy's consolidated net cash from operating activities is provided primarily by its competitive energy services and energy delivery services businesses (see Results of Operations above). Net cash provided from operating activities increased by $44 million during the first three months of 2010 compared to the comparable period in 2009, as summarized in the following table:

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

The decrease in non-cash charges and other adjustments is primarily due to lower net amortization of regulatory assets ($106 million), including CEI’s $216 million regulatory asset impairment recorded in the first quarter of 2009, partially offset by higher net deferred income taxes and investment tax credits ($87 million) and an increase in the provision for depreciation ($16 million). The changes in working capital and other primarily resulted from a $104 million decrease in prepayments and other current assets and an $58 million increase in accrued taxes, partially offset by a $52 million decrease in accrued interest, a $44 million increase in receivables and a $31 million increase in cash collateral paid. The change in accrued taxes and prepayments primarily relates to the timing of income tax payments. The decrease in accrued interest primarily relates to the $1.2 billion tender offer of holding company notes in the third quarter of 2009 combined with the timing of payments relating to new debt issuances in 2009.

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Cash Flows From Financing Activities

In the first three months of 2010, cash used for financing activities was $594 million compared to cash provided from financing activities of $70 million in the first three months of 2009. The decrease was primarily due to new debt issuances in 2009 and the repayment of short-term borrowings in 2010, partially offset by decreased long-term debt redemptions in 2010. The following table summarizes security issuances (net of any discounts) and redemptions.

	Three Months Ended
	March 31
Securities Issued or Redeemed	2010			2009
	(In millions)
New issues
Pollution control notes	$	-		$	100
Unsecured notes		-			600
	$	-		$	700
Redemptions
Pollution control notes	$	-		$	437
Senior secured notes		9			7
Met-Ed unsecured notes		100			-
	$	109		$	444
Short-term borrowings, net	$	(295	)	$	-

Cash Flows From Investing Activities

Net cash flows used in investing activities resulted primarily from property additions. Additions for the energy delivery services segment primarily represent expenditures related to transmission and distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for the three months ended March 31, 2010 and 2009 by business segment:

Summary of Cash Flows	Property
Provided from (Used for) Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Three Months Ended March 31, 2010
Energy delivery services	$	(166	)	$	62		$	(7	)	$	(111	)
Competitive energy services		(323	)		-			(1	)		(324	)
Other		(3	)		-			-			(3	)
Inter-Segment reconciling items		(16	)		(22	)		-			(38	)
Total	$	(508	)	$	40		$	(8	)	$	(476	)
Three Months Ended March 31, 2009
Energy delivery services	$	(165	)	$	51		$	(14	)	$	(128	)
Competitive energy services		(421	)		2			(19	)		(438	)
Other		(49	)		(20	)		1			(68	)
Inter-Segment reconciling items		(19	)		(25	)		-			(44	)
Total	$	(654	)	$	8		$	(32	)	$	(678	)

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

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

GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon either FirstEnergy or its subsidiaries’ credit ratings.

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As of March 31, 2010, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.0 billion, as summarized below:

	Maximum
Guarantees and Other Assurances	Exposure
	(In millions)
FirstEnergy Guarantees on Behalf of its Subsidiaries
Energy and Energy-Related Contracts (1)	$	324
LOC (long-term debt) – interest coverage (2)		6
FirstEnergy guarantee of OVEC obligations		300
Other (3)		297
		927
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts		54
LOC (long-term debt) – interest coverage (2)		6
FES’ guarantee of NGC’s nuclear property insurance		77
FES’ guarantee of FGCO’s sale and leaseback obligations		2,464
		2,601
Surety Bonds		77
LOC (long-term debt) – interest coverage (2)		3
LOC (non-debt) (4)(5)		423
		503
Total Guarantees and Other Assurances	$	4,031

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

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

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

                                                                $1.6 billion is reflected in currently payable long-term debt on FirstEnergy’s

                                                                consolidated balance sheets.

(3)     Includes guarantees of $80 million for nuclear decommissioning funding  

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

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

under FirstEnergy’s revolving credit facility.

(5)             Includes approximately $145 million pledged in connection with the sale and

leaseback of Beaver Valley Unit 2 by OE and $47 million pledged in connection with

the sale and leaseback of Perry by OE.

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

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

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

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Stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase the total potential amount to $656 million, consisting of $38 million due to “material adverse event” contractual clauses, $63 million due to an acceleration of payment or funding obligation, and $555million due to a below investment grade credit rating.

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $77 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ power portfolio as of March 31, 2010, and forward prices as of that date, FES has posted collateral of $270million. Under a hypothetical adverse change in forward prices (95% confidence level change in forward prices over a one year time horizon), FES would be required to post an additional $168 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post higher amounts for margining.

In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in an amount up to $500 million. The Surplus Margin Guaranty is secured by an NGC FMB issued in favor of the Ohio Companies.

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

OFF-BALANCE SHEET ARRANGEMENTS

FES and the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to sale and leaseback arrangements involving the Bruce Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, is $1.7 billion as of March 31, 2010.

MARKET RISK INFORMATION

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

Commodity Price Risk

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

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Increase (Decrease) in the Fair Value of Derivative Contracts	Non-Hedge			Hedge			Total
	(In millions)
Change in the Fair Value of Commodity Derivative Contracts:
Outstanding net liability as of January 1, 2010	$	(630	)	$	(15	)	$	(645	)
Additions/change in value of existing contracts		(276	)		(6	)		(282	)
Settled contracts		94			7			101
Outstanding net liability as of March 31, 2010(1)	$	(812	)	$	(14	)	$	(826	)
Non-Commodity Net Liabilities as of March 31, 2010:
Interest rate swaps	$	-		$	(2	)	$	(2	)
Net Liabilities-Derivative Contracts as of March 31, 2010	$	(812	)	$	(16	)	$	(828	)
Impact of Changes in Commodity Derivative Contracts(2)
Income Statement effects (pre-tax)	$	(27	)	$	-		$	(27	)
Balance Sheet effects:
OCI (pre-tax)	$	-		$	1		$	1
Regulatory asset (net)	$	155		$	-		$	155
(1)     Includes $580 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts.  NUG contracts are subject to regulatory accounting and do not impact earnings.  (2)       Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

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

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	1		$	39		$	40
Other liabilities		(140	)		(47	)		(187	)
Non-Current-
Other deferred charges		158			22			180
Other non-current liabilities		(831	)		(30	)		(861	)
Net liabilities	$	(812	)	$	(16	)	$	(828	)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 3to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of March 31, 2010 are summarized by year in the following table:

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

(1)Represents exchange traded NYMEX futures and options.

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

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

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

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

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Interest Rate Swap Agreements – Fair Value Hedges

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

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

Forward Starting Swap Agreements - Cash Flow Hedges

FirstEnergy used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first three months of 2010, FirstEnergy terminated forward swaps with a notional value of $100 million. The termination of the forward starting swap agreements did not materially impact FirstEnergy’s net income and no forward starting swap agreements were outstanding as of March 31, 2010.

Equity Price Risk

FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover certain employees. The plan provides defined benefits based on years of service and compensation levels. FirstEnergy also provides health care benefits (which include certain employee contributions, deductibles, and co-payments) upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of December 31, 2009, the pension plan was underfunded. FirstEnergy currently estimates that additional cash contributions will be required beginning in 2012. The overall actual investment result during 2009 was a gain of 13.6% compared to an assumed 9% positive return. Based on a 6% discount rate, FirstEnergy’s pre-tax net periodic pension and OPEB expense was $24 million in the first quarter of 2010.

Nuclear decommissioning trust funds have been established to satisfy NGC's and the Utilities' nuclear decommissioning obligations. As of March 31, 2010, approximately 17% of the funds were invested in equity securities and 83% were invested in fixed income securities, with limitations related to concentration and investment grade ratings. The equity securities are carried at their market value of approximately $311 million as of March 31, 2010. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $31 million reduction in fair value as of March 31, 2010. The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts as other-than-temporary impairments. FirstEnergy continues to evaluate the status of its funding obligations for the decommissioning of these nuclear facilities and does not expect to make additional cash contributions to the nuclear decommissioning trusts in 2010 other than the required annual trust contributions.

CREDIT RISK

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

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

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OUTLOOK

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

State Regulatory Matters

Regulatory assets that do not earn a current return totaled approximately $213 million as of March 31, 2010 (JCP&L - $46 million, Met-Ed - $122 million, and Penelec - $47 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets by company:

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

Regulatory assets by source are as follows:

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

Reliability Initiatives

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

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

In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the Midwest ISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards. FirstEnergy’s MISO facilities are next due for the periodic audit by ReliabilityFirst later this year.

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On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation required JCP&L to respond to the NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviews with personnel involved in responding to the event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L replied as requested on August 6, 2009. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittals or interview results.

On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays (out of approximately 20,000 reportable relays) in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. ReliabilityFirst issued an Initial Notice of Alleged Violation on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 2009, and submitted it to the FERC for approval on August 19, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-reported violation.

Ohio

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing. On January 21, 2009, the PUCO granted the Ohio Companies’ application in part to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.

SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter. The PUCO has not yet issued a substantive Entry on Rehearing. The ESP proposed by the Ohio Companies was approved by the PUCO on December 19, 2008.  The Ohio Companies thereafter withdrew and terminated the ESP and continued their rate plan then in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider, which recovered the increased purchased power costs for OE and TE, and recovered a portion of those costs for CEI, with the remainder being deferred for future recovery.

On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP provided that generation would be provided by FES at the average wholesale rate of the CBP described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices would be based upon the outcome of a descending clock CBP on a slice-of-system basis. The Amended ESP further provided that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI would agree to write-off approximately $216 million of its Extended RTC regulatory asset, and that the Ohio Companies would collect a delivery service improvement rider at an overall average rate of $.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressed a number of other issues, including but not limited to, rate design for various customer classes, and resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009.

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SB221 also requires electric distribution utilities to implement energy efficiency programs. Under the provisions of SB221, the Ohio Companies are required to achieve a total annual energy savings equivalent of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional .75% reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies have filed an application with the PUCO seeking such amendments. On January 7, 2010, the PUCO amended the 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years. On March 10, 2010, the PUCO found that due to a change in PUCO rules subsequent to the filing of the Ohio Companies’ application, the Ohio Companies’ application seeking a reduction of the peak demand reduction requirements was moot. In its March 10, 2010, Entry the PUCO also found that the Companies peak demand reduction programs complied with PUCO rules.

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

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

Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they serve in 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs will be used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On December 7, 2009, the Ohio Companies filed an application with the PUCO seeking a force majeure determination regarding the Ohio Companies’ compliance with the 2009 solar energy resources benchmark, and seeking a reduction in the benchmark. On March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and thus granted the Ohio Companies’ application seeking force majeure. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies’ acquired through their 2009 RFP processes, provided the Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2010, the Ohio Companies and FES (due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy requirements in SB221 for 2009. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark, which application is still pending.

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

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

Pennsylvania

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations.

On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. On August 12, 2009, Met-Ed and Penelec filed a settlement agreement with the PPUC for the generation procurement plan covering the period January 1, 2011, through May 31, 2013, reflecting the settlement on all but two issues. The settlement plan proposes a staggered procurement schedule, which varies by customer class. On September 2, 2009, the ALJ issued a Recommended Decision (RD) approving the settlement and adopted the Met-Ed and Penelec’s positions on two reserved issues. On November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two reserved issues. Generation procurement began in January 2010.

On May 22, 2008, the PPUC approved Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The TSCs included a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded. On August 11, 2009, the ALJ issued a Recommended Decision to the PPUC approving Met-Ed’s and Penelec’s TSCs as filed and dismissing all complaints. Exceptions by various interveners were filed and reply exceptions were filed by Met-Ed and Penelec. The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which denies the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directs Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructs Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. On March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of marginal transmission loss costs. By Order entered March 25, 2010, the PPUC granted the requested stay until December 31, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of Met-Ed and Penelec that they should prevail in the appeal and therefore expect to fully recover the approximately $199.7 million ($158.5 million for Met-Ed and $41.2 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On April 2, 2010, Met-Ed and Penelec filed a Response to the PPUC’s March 3, 2010 Order requesting approval of procedures to establish separate accounts to track all marginal transmission loss revenues and related interest and the use of those funds to mitigate future generation rate increases commencing January 1, 2011

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On May 28, 2009, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2009 through May 31, 2010 subject to the outcome of the proceeding related to the 2008 TSC filing described above, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers the new TSC resulted in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers increased to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, the PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs to a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers would increase approximately 9.4% for the period June 2009 through May 2010.

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

Act 129 also required utilities to file by August 14, 2009 with the PPUC smart meter technology procurement and installation plan to provide for the installation of smart meter technology within 15 years. On August 14, 2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan. Consistent with the PPUC’s rules, this plan proposes a 24-month assessment period in which the Pennsylvania Companies will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs at approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. An Initial Decision was issued by the presiding ALJ on January 28, 2010. The ALJ’s Initial Decision approved the Smart Meter Plan as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; eliminating the provision of interest in the 1307(e) reconciliation; providing for the recovery of reasonable and prudent costs minus resulting savings from installation and use of smart meters; and reflecting that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. On April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision issued on January 28, 2010, and decided various issues regarding the Smart Meter Implementation Plan (SMIP) for the Pennsylvania Companies. An order consistent with Chairman Cawley’s Motion is anticipated to be entered in the near future, in which event the Pennsylvania Companies will move forward with the Smart Meter Technology Procurement and Installation Plan.

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

On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the Pennsylvania Companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings.

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

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On February 8, 2010, Penn filed with the PPUC a generation procurement plan covering the period June 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. A preliminary conference was held on March 26, 2010, and, among other things, established a procedural schedule.  Evidentiary hearings are scheduled for June 15-16, 2010. The PPUC is required to issue an order on the plan no later than November 8, 2010.

New Jersey

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31, 2010, the accumulated deferred cost balance totaled approximately $55 million.

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

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. The EMP was issued on October 22, 2008, establishing five major goals:

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

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

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

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

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

On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by New Jersey electric and gas utilities in order to achieve the goals of the EMP. On April 16, 2010, the BPU issued an order indefinitely suspending the requirement of the New Jersey utilities to submit Utility Master Plans until such time as the status of the EMP has been made clear. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations.

In support of former New Jersey Governor Corzine's Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. In addition, approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million would be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent on energy efficiency programs that would complement those currently being offered. The project relating to expansion of the existing demand response programs was approved by the NJBPU on August 19, 2009, and implementation began in 2009. Approval for the project related to energy efficiency programs intended to complement those currently being offered was denied by the NJBPU on December 1, 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal.

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

FERC Matters

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements. On October 29, 2009, March 17, 2010 and April 8, 2010, FirstEnergy, filed additional settlement agreements with FERC to resolve outstanding claims with various parties. FirstEnergy is actively pursuing settlement agreements with other parties to the case. On December 8, 2009, certain parties sought a writ of mandamus from the DC Circuit Court of Appeals directing FERC to issue an order on the Initial Decision. The Court agreed to hold this matter in abeyance based upon FERC’s representation to use good faith efforts to issue a substantive ruling on the initial decision no later than May 27, 2010. If FERC fails to act, the case will be submitted for briefing in June. The outcome of this matter cannot be predicted.

PJM Transmission Rate

On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held on the content of the compliance filings and numerous parties appeared and litigated various issues concerning PJM rate design, notably AEP, which proposed to create a "postage stamp," or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. AEP's proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order (Opinion 494) finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

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

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

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The FERC’s orders on PJM rate design prevented the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a postage-stamp basis reduces the cost of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. FERC has no specific time frame to rule in this matter.

RTO Consolidation

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

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

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

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

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

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

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Changes ordered for PJM Reliability Pricing Model (RPM) Auction

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

On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. It ordered changes included making incremental improvements to RPM and clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; subsequently, numerous parties filed requests for rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied rehearing and request for oral argument of the March 26, 2009 Order.

MISO Complaints Versus PJM

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

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

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

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

Environmental Matters

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

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

Clean Air Act Compliance

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

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

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $399 million for 2010-2012.

In October 2007, PennFuture and three of its members filed a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations, in the U.S. District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the three complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 16, 2009, a settlement reached with PennFuture and one of the three individual complainants was approved by the Court, which dismissed the claims of PennFuture and of the settling individual. The other two non-settling individuals are now represented by counsel handling the three cases filed in July 2008. FGCO believes those claims are without merit and intends to defend itself against the allegations made in those three complaints. The Pennsylvania Department of Health, under a Cooperative Agreement with the Agency for Toxic Substances and Disease Registry, completed a Health Consultation regarding the Mansfield Plant and issued a report dated March 31, 2009, which concluded there is insufficient sampling data to determine if any public health threat exists for area residents due to emissions from the Mansfield Plant. The report recommended additional air monitoring and sample analysis in the vicinity of the Mansfield Plant, which the Pennsylvania Department of Environmental Protection has completed.

In December 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU and Met-Ed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allege that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint in February and September of 2009, respectively. The Court granted Met-Ed's motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties on statute of limitations grounds in order to allow the states to prove either that the application of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.

In January 2009, the EPA issued a NOV to Reliant alleging NSR violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 2009, NOV also alleged NSR violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of the Keystone Station, and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.

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

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

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

National Ambient Air Quality Standards

In March 2005, the EPA finalized CAIR, covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia, based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOX emissions to 1.3 million tons annually. CAIR was challenged in the U.S. Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In September 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. On July 10, 2009, the U.S. Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the "8-hour" ozone NAAQS. FGCO's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

Hazardous Air Pollutant Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the U.S. Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire Court, which denied the petition in May 2008. In October 2008, the EPA (and an industry group) petitioned the U.S. Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. On April 15, 2010, the EPA entered into a consent decree requiring it to propose maximum achievable control technology (MACT) regulations for mercury and other hazardous air pollutants by March 16, 2011, and to finalize the regulations by November 16, 2011. On April 29, 2010, the EPA issued proposed MACT regulations requiring emissions reductions of mercury and other hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels such as the proposed Burger biomass repowering project. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards applicable to electric generating units.  Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’s operations may result.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On December 23, 2009, the Supreme Court of Pennsylvania affirmed the Commonwealth Court of Pennsylvania ruling that Pennsylvania’s mercury rule is “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule.

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Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries. The U.S. signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the U.S. Senate. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, the December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement which recognized the scientific view that the increase in global temperature should be below two degrees Celsius, included a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020, and established the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. Once they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia, and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China, and India, would agree to take mitigation actions, subject to their domestic measurement, reporting, and verification. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the U.S. Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. Also in September 2009, the EPA proposed new thresholds for GHG emissions that define when CAA permits under the NSR and Title V operating permits programs would be required. The EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. The EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that concentrations of several key GHG increase the threat of climate change. In April 2010, EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles requiring an estimated combined average emissions level of 250 grams of CO2 per mile in model year 2016 and clarified that GHG regulation under the CAA will not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest.

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

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

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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 U.S. Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit Court’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. The EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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

Regulation of Waste Disposal

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including regulation as non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion residuals. In December 2009, the EPA provided to FGCO the findings of its review of the Bruce Mansfield Plant’s coal combustion residuals management practices. The EPA observed that the waste management structures and the Plant “appeared to be well maintained and in good working order” and recommended only that FGCO “seal and maintain all asphalt surfaces.” On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA issued a proposed rule that provides two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FGCO's future cost of compliance with any coal combustion residuals regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.

The Utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of March  31, 2010, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $101 million (JCP&L - $74 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy - $24 million) have been accrued through March 31, 2010. Included in the total are accrued liabilities of approximately $67 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

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Other Legal Proceedings

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages.

After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. On March 31, 2009, the trial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was granted by the Appellate Division on June 15, 2009. Plaintiffs filed their appellate brief on August 25, 2009, and JCP&L filed an opposition brief on September 25, 2009. On or about October 13, 2009, Plaintiffs filed their reply brief in further support of their appeal of the trial court's decision decertifying the class. The Appellate Division heard oral argument on January 5, 2010, before a three-judge panel. JCP&L is awaiting the Court’s decision.

Litigation Relating to the Proposed Allegheny Energy Merger

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

Nuclear Plant Matters

Davis Besse Control Rod Drive Mechanism Nozzles

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

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

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

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

Other Legal Matters

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

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009. The parties participated in the federal court's mediation programs and held private settlement discussions. On April 14, 2010, the parties reached a tentative agreement on a settlement package that must be reviewed and approved by the court. JCP&L recognized a liability for the potential $16 million award in 2005, which has been adjusted for post-judgment interest that began to accrue as of February 25, 2009.

On February 16, 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was approved by the PUCO. On March 18, 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas. The court has not yet ruled on that motion to dismiss. The named-defendant companies will continue to defend these claims including challenging any class certification.

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

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

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

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FIRSTENERGY SOLUTIONS CORP.

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services, and through its subsidiaries, FGCO and NGC, owns or leases and operates and maintains FirstEnergy's fossil and hydroelectric generation facilities, and owns FirstEnergy's nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.

FES' revenues are derived from sales to individual retail customers, sales to communities in the form of government aggregation programs and the sale of electricity to affiliated utility companies to meet all or a portion of their PLR and default service requirements. FES' revenues also include wholesale sales non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois.

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

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

Results of Operations

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

Revenues

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

The increase in revenues resulted from the following sources:

	Three Months
	Ended March 31				Increase
Revenues by Type of Service	2010		2009		(Decrease)
	(In millions)
Direct and Government Aggregation	$	512	$	91	$	421
PLR		677		893		(216	)
Wholesale		87		189		(102	)
Transmission		17		25		(8	)
RECs		67		-		67
Other		28		28		-
Total Revenues	$	1,388	$	1,226	$	162

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

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

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

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

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

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

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

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

Expenses

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

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

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

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

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

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

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

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

Other Expense

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

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OHIO EDISON COMPANY

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They procure generation services for those franchise customers electing to retain OE and Penn as their power supplier.

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

Results of Operations

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

Revenues

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

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

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

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

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

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

99

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

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

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

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

Expenses

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

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

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

100

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also procures generation services for those customers electing to retain CEI as their power supplier.

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

Results of Operations

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

Revenues

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

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

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

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

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

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

101

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

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

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

Expenses

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

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

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

102

THE TOLEDO EDISON COMPANY

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also procures generation services for those customers electing to retain TE as their power supplier.

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

Results of Operations

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

Revenues

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

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

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

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

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

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

103

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

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

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

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

Expenses

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

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

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

Other Expense

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

104

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also procures generation services for franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.

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

Results of Operations

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

Revenues

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

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

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

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

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

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

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

105

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

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

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

Expenses

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

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

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

106

METROPOLITAN EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also procures generation service for those customers electing to retain Met-Ed as their power supplier. Met-Ed has a partial requirements wholesale power sales agreement with FES, to supply nearly all of its energy requirements at fixed prices through 2010.

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

Results of Operations

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

Revenues

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

Distribution revenues increased $24million in the first three months of 2010, compared to the same period of 2009, primarily due to higher transmission rates, resulting from the annual update to Met-Ed’s TSC rider effective June 1, 2009, partially offset by lower CTC rates for the residential class resulting from a PPUC-approved NUG Statement Compliance filing. Lower KWH deliveries to residential customers reflect reduced weather-related usage due to a 7.3% decrease in heating degree days in the first three months of 2010, compared to the same period of 2009. Higher industrial KWH deliveries were due to the recovering economy.

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

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

Distribution Revenues	Increase
	(In millions)
Residential	$	7
Commercial		10
Industrial		7
Increase in Distribution Revenues	$	24

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

107

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

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

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

	Increase
Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	3
Commercial		(1	)
Industrial		1
Net Increase in Retail Generation Revenues	$	3

Transmission revenues decreased $6million in the first three months of 2010 compared to the same period of 2009 primarily due to decreased revenues related to Met-Ed’s Financial Transmission Rights. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

Expenses

Total operating expenses increased $46 million in the first three months of 2010 compared to the same period of 2009. The following table presents changes from the prior year by expense category:

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

Purchased power costs increased $29 million in the first three months of 2010 due to an increase in unit costs, partially offset by reduced volumes purchased as a result of lower KWH sales requirements. The net amortization of regulatory assets increased $21 million in the first three months of 2010 compared to the same period of 2009 primarily due to increased transmission cost recovery. Other operating costs decreased $4 million in the first three months of 2010 primarily due to lower employee benefit expenses.

Other Expense

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

108

PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also procures generation services for those customers electing to retain Penelec as their power supplier. Penelec has a partial requirements wholesale power sales agreement with FES, to supply nearly all of its energy requirements at fixed prices through 2010.

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

Results of Operations

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

Revenues

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

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

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

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

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

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

109

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

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

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

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

Transmission revenues decreased by $4million in the first three months of 2010, compared to the same period of 2009, primarily due to lower revenues related to Penelec’s Financial Transmission Rights. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

Expenses

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

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

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

Other Expense

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

110

ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4.   CONTROLS AND PROCEDURES

(a)      EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY

FirstEnergy's management, with the participation of its chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15(d)-15(e), as of the end of the period covered by this report. Based on that evaluation, the chief executive officer  and chief financial officer have concluded that the registrant's disclosure controls and procedures were effective as of the end of the period covered by this report.

(b)      CHANGES IN INTERNAL CONTROLS

During the quarter ended March 31, 2010, there were no changes in FirstEnergy's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant's internal control over financial reporting.

ITEM 4T. CONTROLS AND PROCEDURES – FES, OE, CEI, TE, JCP&L, MET-ED AND PENELEC

(a)      EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Each registrant's management, with the participation of its chief executive officer and chief financial officer, have reviewed and evaluated the effectiveness of such registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15(d)-15(e), as of the end of the period covered by this report. Based on that evaluation, each registrant’s chief executive officer and chief financial officer have concluded that such registrant's disclosure controls and procedures were effective as of the end of the period covered by this report.

(b)      CHANGES IN INTERNAL CONTROLS

During the quarter ended March 31, 2010, there were no changes in the registrants' internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the registrants' internal control over financial reporting.

111

PART II. OTHER INFORMATION

ITEM 1.   LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 8 and 9 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

FirstEnergy's Annual Report on Form 10-K for the year ended December 31, 2009, includes a detailed discussion of its risk factors. There have been no material changes to these risk factors for the quarter ended March 31, 2010.

ITEM 2.   UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

(c)      FirstEnergy

The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock during the first quarter of 2010.

		Period
		January	February	March	First Quarter
Total Number of Shares Purchased (a)		64,186	188,695	1,184,918	1,437,799
Average Price Paid per Share		$45.35	$39.56	$39.06	$39.41
Total Number of Shares Purchased
As Part of Publicly Announced Plans
or Programs		-	-	-	-
Maximum Number (or Approximate Dollar
Value) of Shares that May Yet Be
Purchased Under the Plans or Programs		-	-	-	-
(a)	Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver commonstock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan.

ITEM 5.   OTHER INFORMATION

None

ITEM 6.   EXHIBITS

Exhibit Number
FirstEnergy
	2.1	Agreement and Plan of Merger, dated as of February 10, 2010, by and among FirstEnergy Corp., Element Merger Sub, Inc. and Allegheny Energy, Inc. (incorporated by reference to FirstEnergy’s Form 8-K filed February 11, 2010, Exhibit 2.1, File No. 333-21011)
	12	Fixed charge ratios
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101*	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended March 31, 2010, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.
		Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K.  The Registrant will furnish the omitted schedules to the Securities and Exchange Commission upon request by the Commission.

112

FES
	12	Fixed charge ratios
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
OE
	12	Fixed charge ratios
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
CEI
	12	Fixed charge ratios
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
TE
	12		Fixed charge ratios
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
JCP&L
	12		Fixed charge ratios
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
Met-Ed
	12		Fixed charge ratios
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
Penelec
	12		Fixed charge ratios
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

* Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited and, as a result, investors should not rely on the XBRL-Related Documents in making investment decisions. Furthermore, users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

Pursuant to reporting requirements of respective financings, FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

May 4, 2010

FIRSTENERGY CORP.

Registrant

FIRSTENERGY SOLUTIONS CORP.

Registrant

OHIO EDISON COMPANY

Registrant

THE CLEVELAND ELECTRIC

ILLUMINATING COMPANY

Registrant

THE TOLEDO EDISON COMPANY

Registrant

METROPOLITAN EDISON COMPANY

Registrant

PENNSYLVANIA ELECTRIC COMPANY

Registrant

/s/ Harvey L. Wagner

Harvey L. Wagner

Vice President, Controller

and Chief Accounting Officer

JERSEY CENTRAL POWER & LIGHT COMPANY

Registrant

/s/ Kevin R. Burgess

Kevin R. Burgess

Controller

(Principal Accounting Officer)

114